Item 8. Financial Statements and Supplementary Data

285K characters. Original on sec.gov · Markdown

Item 8. Financial Statements and Supplementary Data



	INDEX TO FINANCIAL STATEMENTS CHESAPEAKE ENERGY CORPORATION
		Page
Management’s Report on Internal Control Over Financial Reporting		74
Report of Independent Registered Public Accounting Firm		75
Consolidated Financial Statements:
	Consolidated Balance Sheets as of December 31, 2016 and 2015	76
	Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014	78
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2016, 2015 and 2014	79
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014	80
	Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014	82
	Notes to the Consolidated Financial Statements
	Note 1. Basis of Presentation and Summary of Significant Accounting Policies	84
	Note 2. Earnings per Share	91
	Note 3. Debt	93
	Note 4. Contingencies and Commitments	99
	Note 5. Other Liabilities	102
	Note 6. Income Taxes	103
	Note 7. Related Party Transactions	106
	Note 8. Equity	106
	Note 9. Share-Based Compensation	111
	Note 10. Employee Benefit Plans	115
	Note 11. Derivative and Hedging Activities	116
	Note 12. Oil and Natural Gas Property Transactions	123
	Note 13. Spin-Off of Oilfield Services Business	127
	Note 14. Investments	128
	Note 15. Variable Interest Entities	129
	Note 16. Other Property and Equipment	130
	Note 17. Impairments	131
	Note 18. Restructuring and Other Termination Costs	132
	Note 19. Fair Value Measurements	133
	Note 20. Asset Retirement Obligations	134
	Note 21. Major Customers and Segment Information	134
	Note 22. Recently Issued Accounting Standards	138
	Note 23. Subsequent Events	139
Supplementary Information		140
	Quarterly Financial Data (unaudited)	140
	Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited)	141

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 Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended).

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.

Under the supervision and with the participation of our management, including the CEO and the CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016 using the criteria established in “Internal Control-Integrated Framework” (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

We did not effectively design and maintain controls over the review of the valuation of proved oil and natural gas properties and the accuracy of impairment of oil and natural gas properties. Specifically, the review of the initial configuration of a newly implemented tool used to calculate basis price differentials did not detect an error in the formula in the calculations, and the manual interface control to agree data used in the tool to the general ledger was not designed to validate the data at an appropriately disaggregated level.

The control deficiency did not result in a material misstatement to the Company’s consolidated financial statements for the year ended December 31, 2016. However, the control deficiency could result in misstatements of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, our management has determined that this control deficiency constitutes a material weakness.

Because of this material weakness, management concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2016.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2016 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


March 3, 2017

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Chesapeake Energy Corporation

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Chesapeake Energy Corporation and its subsidiaries at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because a material weakness in internal control over financial reporting related to the review of the valuation of proved oil and natural gas properties and the accuracy of impairment of oil and natural gas properties existed as of that date. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in the accompanying Management's Report on Internal Control over Financial Reporting. We considered this material weakness in determining the nature, timing, and extent of audit tests applied in our audit of the 2016 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. The Company's management is responsible for these 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 management's report referred to above. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. 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.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for debt issuance costs in 2016.

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.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

March 3, 2017

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS



	December 31,
	2016			2015
	($ in millions)
CURRENT ASSETS:
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$	882		$	825
Accounts receivable, net	1,057			1,129
Short-term derivative assets	—			366
Other current assets	203			160
Total Current Assets	2,142			2,480
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)	66,451			63,843
Unproved properties	4,802			6,798
Other property and equipment	2,053			2,927
Total Property and Equipment, at Cost	73,306			73,568
Less: accumulated depreciation, depletion and amortization (($458) and ($428) attributable to our VIE)	(62,726		)	(59,365		)
Property and equipment held for sale, net	29			95
Total Property and Equipment, Net	10,609			14,298
LONG-TERM ASSETS:
Long-term derivative assets	—			246
Other long-term assets	277			290
TOTAL ASSETS	$	13,028		$	17,314

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS – (Continued)



	December 31,
	2016			2015
	($ in millions)
CURRENT LIABILITIES:
Accounts payable	$	672		$	944
Current maturities of long-term debt, net	503			381
Accrued interest	113			101
Short-term derivative liabilities	562			40
Other current liabilities ($3 and $8 attributable to our VIE)	1,798			2,219
Total Current Liabilities	3,648			3,685
LONG-TERM LIABILITIES:
Long-term debt, net	9,938			10,311
Long-term derivative liabilities	15			60
Asset retirement obligations, net of current portion	247			452
Other long-term liabilities	383			409
Total Long-Term Liabilities	10,583			11,232
CONTINGENCIES AND COMMITMENTS (Note 4)
EQUITY:
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 5,839,506 and 7,251,515 shares outstanding	1,771			3,062
Common stock, $0.01 par value, 1,500,000,000 and 1,000,000,000 shares authorized: 896,279,353 and 664,795,509 shares issued	9			7
Additional paid-in capital	14,486			12,403
Accumulated deficit	(17,603		)	(13,202		)
Accumulated other comprehensive loss	(96		)	(99		)
Less: treasury stock, at cost; 1,220,504 and 1,437,724 common shares	(27		)	(33		)
Total Chesapeake Stockholders’ Equity (Deficit)	(1,460		)	2,138
Noncontrolling interests	257			259
Total Equity (Deficit)	(1,203		)	2,397
TOTAL LIABILITIES AND EQUITY	$	13,028		$	17,314

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,
	2016			2015			2014
	($ in million except per share data)
REVENUES:
Oil, natural gas and NGL	$	3,288		$	5,391		$	10,354
Marketing, gathering and compression	4,584			7,373			12,225
Oilfield services	—			—			546
Total Revenues	7,872			12,764			23,125
OPERATING EXPENSES:
Oil, natural gas and NGL production	710			1,046			1,208
Oil, natural gas and NGL gathering, processing and transportation	1,855			2,119			2,174
Production taxes	74			99			232
Marketing, gathering and compression	4,778			7,130			12,236
Oilfield services	—			—			431
General and administrative	240			235			322
Restructuring and other termination costs	6			36			7
Provision for legal contingencies	123			353			234
Oil, natural gas and NGL depreciation, depletion and amortization	1,003			2,099			2,683
Depreciation and amortization of other assets	104			130			232
Impairment of oil and natural gas properties	2,564			18,238			—
Impairments of fixed assets and other	838			194			88
Net (gains) losses on sales of fixed assets	(12		)	4			(199		)
Total Operating Expenses	12,283			31,683			19,648
INCOME (LOSS) FROM OPERATIONS	(4,411		)	(18,919		)	3,477
OTHER INCOME (EXPENSE):
Interest expense	(296		)	(317		)	(89		)
Losses on investments	(8		)	(96		)	(75		)
Impairments of investments	(119		)	(53		)	(5		)
Net gain (loss) on sales of investments	(10		)	—			67
Gains (losses) on purchases or exchanges of debt	236			279			(197		)
Other income	19			8			22
Total Other Expense	(178		)	(179		)	(277		)
INCOME (LOSS) BEFORE INCOME TAXES	(4,589		)	(19,098		)	3,200
INCOME TAX EXPENSE (BENEFIT):
Current income taxes	(19		)	(36		)	47
Deferred income taxes	(171		)	(4,427		)	1,097
Total Income Tax Expense (Benefit)	(190		)	(4,463		)	1,144
NET INCOME (LOSS)	(4,399		)	(14,635		)	2,056
Net income attributable to noncontrolling interests	(2		)	(50		)	(139		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(4,401		)	(14,685		)	1,917
Preferred stock dividends	(97		)	(171		)	(171		)
Loss on exchange of preferred stock	(428		)	—			—
Repurchase of preferred shares of CHK Utica	—			—			(447		)
Earnings allocated to participating securities	—			—			(26		)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	(4,926	)	$	(14,856	)	$	1,273
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	(6.45	)	$	(22.43	)	$	1.93
Diluted	$	(6.45	)	$	(22.43	)	$	1.87
CASH DIVIDEND DECLARED PER COMMON SHARE	$	—		$	0.0875		$	0.35
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	764			662			659
Diluted	764			662			772

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,
	2016			2015			2014
	($ in millions)
NET INCOME (LOSS)	$	(4,399	)	$	(14,635	)	$	2,056
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of ($14), $12 and $0	(13		)	20			1
Reclassification of losses on settled derivative instruments, net of income tax expense of $18, $15 and $14	16			24			23
Reclassification of (gains) losses on investment, net of income tax expense (benefit) of $0, $0 and ($3)	—			—			(5		)
Other Comprehensive Income (Loss)	3			44			19
COMPREHENSIVE INCOME (LOSS)	(4,396		)	(14,591		)	2,075
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(2		)	(50		)	(139		)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	(4,398	)	$	(14,641	)	$	1,936

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,
	2016			2015			2014
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET (INCOME) LOSS	$	(4,399	)	$	(14,635	)	$	2,056
ADJUSTMENTS TO RECONCILE NET LOSS TO CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:
Depreciation, depletion and amortization	1,107			2,229			2,915
Deferred income tax expense (benefit)	(171		)	(4,427		)	1,097
Derivative (gains) losses, net	739			(932		)	(1,102		)
Cash receipts (payments) on derivative settlements, net	448			1,123			(253		)
Stock-based compensation	52			78			59
Impairment of oil and natural gas properties	2,564			18,238			—
Net (gains) losses on sales of fixed assets	(12		)	4			(199		)
Renegotiation of natural gas gathering contracts	(115		)	—			—
Impairments of fixed assets and other	467			175			58
Losses on investments	8			96			75
Net (gain) loss on sales of investment	10			—			(67		)
Impairments of investments	119			53			5
(Gains) losses on purchases or exchanges of debt	(236		)	(304		)	63
Restructuring and other termination costs	3			(14		)	(15		)
Provision for legal contingencies	87			340			234
Other	(143		)	244			220
(Increase) decrease in accounts receivable and other assets	21			1,186			(21		)
Decrease in accounts payable, accrued liabilities and other	(753		)	(2,220		)	(491		)
Net Cash Provided By (Used In) Operating Activities	(204		)	1,234			4,634
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(1,295		)	(3,095		)	(4,581		)
Acquisitions of proved and unproved properties	(788		)	(533		)	(1,311		)
Proceeds from divestitures of proved and unproved properties	1,406			189			5,813
Additions to other property and equipment	(37		)	(143		)	(726		)
Proceeds from sales of other property and equipment	131			89			1,003
Cash paid for title defects	(69		)	—			—
Additions to investments	—			(1		)	—
Proceeds from sales of investments	—			—			239
Decrease in restricted cash	—			52			37
Other	(8		)	(9		)	(20		)
Net Cash Provided By (Used In) Investing Activities	(660		)	(3,451		)	454

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,
	2016			2015			2014
	($ in millions)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to purchase debt	(2,734		)	(508		)	(3,362		)
Proceeds from revolving credit facilities borrowings	5,146			—			7,406
Payments on revolving credit facilities borrowings	(5,146		)	—			(7,788		)
Proceeds from issuance of senior notes, net of discount and offering costs	2,210			—			2,966
Proceeds from issuance of term loan, net of offering costs	1,476			—			—
Proceeds from issuance of oilfield services term loan, net of issuance costs	—			—			394
Proceeds from issuance of oilfield services senior notes, net of issuance costs	—			—			494
Cash held and retained by SSE at spin-off	—			—			(8		)
Cash paid for common stock dividends	—			(118		)	(234		)
Cash paid for preferred stock dividends	—			(171		)	(171		)
Cash paid on financing derivatives	—			—			(53		)
Cash paid to repurchase noncontrolling interest of CHK C-T	—			(143		)	—
Cash paid to repurchase preferred shares of CHK Utica	—			—			(1,254		)
Distributions to noncontrolling interest owners	(10		)	(85		)	(173		)
Other	(21		)	(41		)	(34		)
Net Cash Provided By (Used In) Financing Activities	921			(1,066		)	(1,817		)
Net increase (decrease) in cash and cash equivalents	57			(3,283		)	3,271
Cash and cash equivalents, beginning of period	825			4,108			837
Cash and cash equivalents, end of period	$	882		$	825		$	4,108

Supplemental disclosures to the consolidated statements of cash flows are presented below:

	Years Ended December 31,
	2016			2015			2014
	($ in millions)
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	$	344		$	235		$	96
Income taxes paid, net of refunds received	$	(27	)	$	44		$	10

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in accrued drilling and completion costs	$	(23	)	$	(148	)	$	(84	)
Change in accrued acquisitions of proved and unproved properties	$	(13	)	$	55		$	(74	)
Change in divested proved and unproved properties	$	52		$	35		$	38
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,
	2016			2015			2014
	($ in millions)
PREFERRED STOCK:
Balance, beginning of period	$	3,062		$	3,062		$	3,062
Conversions of 1,412,009, 0 and 0 shares of preferred stock for common stock	(1,291		)	—			—
Balance, end of period	1,771			3,062			3,062
COMMON STOCK:
Balance, beginning of period	7			7			7
Exchange of senior notes and contingent convertible notes	1			—			—
Conversion of preferred stock	1			—			—
Balance, end of period	9			7			7
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period	12,403			12,531			12,446
Stock-based compensation	64			71			47
Exchange of contingent convertible notes for 55,427,782, 0 and 0 shares of common stock	241			—			—
Exchange of senior notes for 53,923,925, 0 and 0 shares of common stock	229			—			—
Conversion of preferred stock for 120,186,195, 0 and 0 shares of common stock	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	(16		)	—			—
Exercise of stock options	—			—			23
Dividends on common stock	—			(59		)	—
Dividends on preferred stock	—			(128		)	—
Issuance costs	(5		)	—			—
Increase (decrease) in tax benefit from stock-based compensation	—			(12		)	15
Balance, end of period	14,486			12,403			12,531
RETAINED EARNINGS (ACCUMULATED DEFICIT):
Balance, beginning of period	(13,202		)	1,483			688
Net income (loss) attributable to Chesapeake	(4,401		)	(14,685		)	1,917
Dividends on common stock	—			—			(234		)
Dividends on preferred stock	—			—			(171		)
Spin-off of oilfield services business	—			—			(270		)
Repurchase of preferred shares of CHK Utica	—			—			(447		)
Balance, end of period	(17,603		)	(13,202		)	1,483
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance, beginning of period	(99		)	(143		)	(162		)
Hedging activity	3			44			24
Investment activity	—			—			(5		)
Balance, end of period	(96		)	(99		)	(143		)

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,
	2016			2015			2014
	($ in millions)
TREASURY STOCK – COMMON:
Balance, beginning of period	(33		)	(37		)	(46		)
Purchase of 37,871, 54,493 and 34,678 shares for company benefit plans	—			(1		)	(1		)
Release of 255,091, 231,081 and 422,395 shares from company benefit plans	6			5			10
Balance, end of period	(27		)	(33		)	(37		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT)	(1,460		)	2,138			16,903
NONCONTROLLING INTERESTS:
Balance, beginning of period	259			1,302			2,145
Net income attributable to noncontrolling interests	2			50			139
Distributions to noncontrolling interest owners	(4		)	(78		)	(169		)
Repurchase of noncontrolling interest of CHK C-T	—			(1,015		)	—
Repurchase of preferred shares of CHK Utica	—			—			(807		)
Deconsolidation of investments, net	—			—			(6		)
Balance, end of period	257			259			1,302
TOTAL EQUITY (DEFICIT)	$	(1,203	)	$	2,397		$	18,205

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" 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. We also own oil and natural gas marketing and compression businesses. As of December 31, 2016, we have sold substantially all of our assets associated with our natural gas gathering business, and prior to June 30, 2014, we owned an oilfield services business (see Note 13). Our operations are located onshore in the United States.

Basis of Presentation

The accompanying consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States (U.S. 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 U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

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 actual results differing significantly from our estimates.

Risks and Uncertainties

Our ability to grow, make capital expenditures and service our debt depends primarily upon the prices we receive for the oil, natural gas and natural gas liquids (NGL) we sell. Substantial expenditures are required to replace reserves, sustain production and fund our business plans. Historically, oil and natural gas prices have been very volatile, and may be subject to wide fluctuations in the future. The substantial decline in oil, natural gas and NGL prices from 2014 levels has negatively affected the amount of liquidity we have available for capital expenditures and debt service. A substantial or extended decline in oil, natural gas and NGL prices could have a material impact on our financial position, results of operations, cash flows and on the quantities of reserves that we may economically produce. Other risks and uncertainties that could affect us in a low commodity price environment include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks and our ability to meet financial ratios and covenants in our financing agreements.

Consolidation

Chesapeake consolidates 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 Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its 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. See Note 14 for further discussion of our investments. Undivided interests in oil and natural gas properties are consolidated on a proportionate basis.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

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.

We continually monitor our consolidated VIE to determine if any events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs.

Cash and Cash Equivalents

For purposes of the consolidated financial statements, Chesapeake considers 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 which are judged 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. During 2016, 2015 and 2014, we recognized $10 million, $4 million and $2 million of bad debt expense related to potentially uncollectible receivables. Accounts receivable as of December 31, 2016 and 2015 are detailed below.



	December 31,
	2016			2015
	($ in millions)
Oil, natural gas and NGL sales	$	840		$	696
Joint interest	156			230
Other	93			226
Allowance for doubtful accounts	(32		)	(23		)
Total accounts receivable, net	$	1,057		$	1,129

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Oil and Natural Gas Properties

Chesapeake follows 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, 2016 were prepared by an independent engineering firm and Chesapeake's internal staff. Approximately 70% by volume and 83% by value of these proved reserves estimates as of December 31, 2016 were prepared by an independent engineering firm. 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.

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, 2016 and the year in which the associated costs were incurred.



	Year of Acquisition
	2016		2015		2014		Prior		Total
	($ in millions)
Leasehold cost	$	109	$	99	$	507	$	2,956	$	3,671
Exploration cost	24		36		13		34		107
Capitalized interest	194		201		184		445		1,024
Total	$	327	$	336	$	704	$	3,435	$	4,802

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 Securities and Exchange Commission (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, 2016, 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 reserves 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 expense.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. The Company reviews its 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.

Other Property and Equipment

Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computers and office equipment. We have no remaining oilfield services equipment as a result of the spin-off of our oilfield services business in 2014, as discussed in Note 13. 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. See Note 16 for further discussion of our gains and losses on the sales of other property and equipment for the years ended 2016, 2015 and 2014 and a summary of our other property and equipment held for sale as of December 31, 2016 and 2015. Other property and equipment costs, excluding land, are depreciated on a straight-line basis.

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. During 2016, 2015 and 2014, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 17 for further discussion of these impairments.

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, 2016 and 2015 are liabilities of approximately $77 million and $60 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, 2016 and 2015, totaled $32 million and $31 million, respectively, and are being amortized over the life of credit facility using the effective interest method. Included in debt are costs associated with the issuance of our senior notes. The remaining unamortized issuance costs as of December 31, 2016 and 2015, totaled $64 million and $43 million, respectively, and are being amortized over the life of the senior notes using the effective interest method.

Environmental Remediation Costs

Chesapeake records 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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 20 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.

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, 2016 and 2015, was $9 million and $10 million, respectively.

Marketing, Gathering and Compression Sales. Chesapeake takes title to the oil, natural gas and NGL it purchases from other interest owners at defined delivery points and delivers 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, including 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, Chesapeake's results of operations related to its 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.

Oilfield Services Revenue. Prior to the spin-off of our oilfield services business in June 2014, we reported oilfield services revenue. Our former oilfield services operating segment was responsible for contract drilling, hydraulic fracturing, rentals, trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Revenues were recognized upon completion stages for our contract drilling, hydraulic fracturing and other oilfield services. Revenue was recognized ratably over the term of the rental for our oilfield rental services. Oilfield trucking services revenue was recognized as services were performed.

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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Derivatives

Derivative instruments are recorded on our consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s 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 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 (i.e., commodity, interest rate and cross currency contracts) 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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Share-Based Compensation

Chesapeake’s 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 in our financial statements 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.

Reclassifications and Revisions

In April 2015, the Financial Accounting Standards Board (FASB) issued guidance that requires debt issuance costs related to term debt to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard requires retrospective application and is effective for annual reporting periods beginning after December 15, 2015. This change in accounting principle is preferable since it allows both debt issuance costs and debt discounts to be presented similarly in the consolidated balance sheets as a direct reduction from the face amount of our debt balances. A retrospective change to our consolidated balance sheet as of December 31, 2015, as previously presented, is required pursuant to the guidance. The retrospective adjustment to the December 31, 2015 consolidated balance sheet is shown below.



	As Previously Reported		December 31, 2015 Adjustment Effect			As Adjusted
	($ in millions)
Other long-term assets	$	333	$	(43	)	$	290
Long-term debt, net	$	10,354	$	(43	)	$	10,311

In addition, certain revisions have been made to the fair value of debt table included in Note 3 to conform to the presentation used for our 2016 disclosure. The 8.00% Senior Secured Second Lien Notes due 2022 were previously classified as Level 1 and should have been classified as Level 2, as these senior notes are not exchange-traded. The following table reflects the revisions made.



	As Previously Reported				December 31, 2015 Adjustment Effect						As Revised
	Carrying Amount		Estimated Fair Value		Carrying Amount			Estimated Fair Value			Carrying Amount		Estimated Fair Value
	($ in millions)
Short-term debt (Level 1)	$	381	$	366	$	—		$	—		$	381	$	366
Long-term debt (Level 1)(a)	$	10,347	$	3,735	$	(3,627	)	$	(1,189	)	$	6,720	$	2,546
Long-term debt (Level 2)	$	—	$	—	$	3,584		$	1,189		$	3,584	$	1,189

(a) The difference in the carrying amount is due to the debt issuance costs retrospective change noted above.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


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 the years ended December 31, 2016, 2015 and 2014, 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 notes and contingent convertible senior notes.

For the years ended December 31, 2016, 2015 and 2014, shares of common stock for the following dilutive securities were excluded from the calculation of diluted EPS as the effect was antidilutive.



		Shares
		(in millions)
Year Ended December 31, 2016
Common stock equivalent of our preferred stock outstanding:
5.75% cumulative convertible preferred stock		34
5.75% cumulative convertible preferred stock (series A)		18
5.00% cumulative convertible preferred stock (series 2005B)		5
4.50% cumulative convertible preferred stock		6
Participating securities		1
Common stock equivalent of our convertible senior notes outstanding:
5.5% convertible senior notes		146
Common stock equivalent of our preferred stock outstanding prior to exchange:
5.75% cumulative convertible preferred stock exchanged		19
5.75% cumulative convertible preferred stock (series A) exchanged		18
5.00% cumulative convertible preferred stock (series 2005B) exchanged		—

Year Ended December 31, 2015
Common stock equivalent of our preferred stock outstanding:
5.75% cumulative convertible preferred stock		59
5.75% cumulative convertible preferred stock (series A)		42
5.00% cumulative convertible preferred stock (series 2005B)		6
4.50% cumulative convertible preferred stock		6
Participating securities		1

Year Ended December 31, 2014
Participating securities		3

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

For the year ended December 31, 2014, all outstanding equity securities convertible into common stock were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the year ended December 31, 2014 is as follows:



	Income (Numerator)		Weighted Average Shares (Denominator)	Per Share Amount
	(in millions, except per share data)
For the Year Ended December 31, 2014:
Basic EPS	$	1,273	659	$	1.93
Effect of Dilutive Securities:
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 5.75% cumulative convertible preferred stock	86		59
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)	63		42
Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)	10		6
Common shares assumed issued for 4.50% cumulative convertible preferred stock	12		6
Diluted EPS	$	1,444	772	$	1.87

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, 2016 and 2015:



	December 31, 2016						December 31, 2015
	Principal Amount			Carrying Amount			Principal Amount			Carrying Amount
	($ in millions)
Term loan due 2021	$	1,500		$	1,500		$	—		$	—
3.25% senior notes due 2016	—			—			381			381
6.25% euro-denominated senior notes due 2017(a)	258			258			329			329
6.5% senior notes due 2017	134			134			453			453
7.25% senior notes due 2018	64			64			538			538
Floating rate senior notes due 2019	380			380			1,104			1,104
6.625% senior notes due 2020	780			780			822			822
6.875% senior notes due 2020	279			279			304			304
6.125% senior notes due 2021	550			550			589			589
5.375% senior notes due 2021	270			270			286			286
4.875% senior notes due 2022	451			451			639			639
8.00% senior secured second lien notes due 2022(b)	2,419			3,409			2,425			3,584
5.75% senior notes due 2023	338			338			384			384
8.00% senior notes due 2025	1,000			1,000			—			—
5.5% convertible senior notes due 2026(c)(e)	1,250			811			—			—
2.75% contingent convertible senior notes due 2035(d)	2			2			2			2
2.5% contingent convertible senior notes due 2037(d)(e)	114			112			1,110			1,027
2.25% contingent convertible senior notes due 2038(d)(e)	200			180			340			290
Revolving credit facility	—			—			—			—
Debt issuance costs	—			(64		)	—			(43		)
Discount on senior notes	—			(16		)	—			(4		)
Interest rate derivatives(f)	—			3			—			7
Total debt, net	9,989			10,441			9,706			10,692
Less current maturities of long-term debt, net(g)	(506		)	(503		)	(381		)	(381		)
Total long-term debt, net	$	9,483		$	9,938		$	9,325		$	10,311


(a)	The principal and carrying amounts shown are based on the exchange rate of $1.0517 to €1.00 and $1.0862 to €1.00 as of December 31, 2016 and 2015, respectively. See Foreign Currency Derivatives in Note 11 for information on our related foreign currency derivatives.


(b)	The carrying amounts as of December 31, 2016 and 2015, include premium amounts of $990 million and $1.159 billion, respectively, associated with a troubled debt restructuring. The premium is being amortized based on an effective yield method.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


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

Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, the notes are convertible 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 a threshold amount during a specified period in a fiscal quarter, beginning with the first quarter of 2017. Convertibility based on common stock price is measured quarterly. 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, 2016. 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.

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.


(d)	The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows:

Holders’ Demand Repurchase Rights. The holders of our contingent 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 on any of four dates that are five, ten, fifteen and twenty years before the maturity date.

Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, the notes are convertible into cash and, if applicable, our common stock using a net share settlement process. One triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period within a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the specified period in the fourth quarter of 2016, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash or common stock in the first quarter of 2017 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 years ended December 31, 2016, 2015 and 2014. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of the principal amount.

Contingent Interest. We will pay contingent interest on the contingent convertible senior notes after they have been outstanding at least ten years during certain periods if the average trading price of the notes exceeds the threshold defined in the indenture.

The holders’ demand repurchase dates, the common stock price conversion threshold amounts (as adjusted to give effect to cash dividends on our common stock) and the ending date of the first six-month period in which contingent interest may be payable for the contingent convertible senior notes are as follows:



Contingent Convertible Senior Notes	Holders' Demand Repurchase Dates	Common Stock Price Conversion Thresholds		Contingent Interest First Payable (if applicable)
2.75% due 2035	November 15, 2020, 2025, 2030	$	45.02	May 14, 2016
2.5% due 2037	May 15, 2017, 2022, 2027, 2032	$	59.44	November 14, 2017
2.25% due 2038	December 15, 2018, 2023, 2028, 2033	$	100.20	June 14, 2019

Optional Redemption by the Company. We may redeem the contingent convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash. In addition, we may redeem our 2.75% Contingent Convertible Senior Notes due 2035 at any time.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


(e)	The carrying amounts as of December 31, 2016 and 2015 are reflected net of discounts of $461 million and $133 million, respectively, associated with the equity component of our convertible and contingent convertible senior notes. This amount is being amortized based on an effective yield method through the first demand repurchase date as applicable.


(f)	See Interest Rate Derivatives in Note 11 for further discussion related to these instruments.


(g)	As of December 31, 2016, current maturities of long-term debt, net includes our 6.25% Euro-denominated Senior Notes due 2017, 6.5% Senior Notes due 2017 and our 2.5% Contingent Convertible Senior Notes due 2037 (2037 Notes). As discussed in footnote (b) above, the holders of our 2037 Notes could exercise their individual demand repurchase rights on May 15, 2017, which would require us to repurchase all or a portion of the principal amount of the notes. As of December 31, 2016, there was $2 million associated with the equity component of the 2037 Notes.

(g)

As of December 31, 2016, current maturities of long-term debt, net includes our 6.25% Euro-denominated Senior Notes due 2017, 6.5% Senior Notes due 2017 and our 2.5% Contingent Convertible Senior Notes due 2037 (2037 Notes). As discussed in footnote (b) above, the holders of our 2037 Notes could exercise their individual demand repurchase rights on May 15, 2017, which would require us to repurchase all or a portion of the principal amount of the notes. As of December 31, 2016, there was $2 million associated with the equity component of the 2037 Notes.

Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes, for the five years ended after December 31, 2016 and thereafter are as follows:



	Principal Amount of Debt Securities
	($ in millions)
2017	$	506
2018	264
2019	380
2020	1,061
2021	2,320
2022 and thereafter	5,458
Total	$	9,989

See Note 23 for discussion of debt that has been retired, repurchased and redeemed in 2017.

Term Loan Facility

In 2016, we entered into a secured five-year term loan facility in aggregate principal amount of $1.5 billion for net proceeds of approximately $1.476 billion. Our obligations under the new 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 loan was made at par without original discount. We used the net proceeds to finance tender offers for our unsecured notes. 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.

Events of default under the term loan include, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to other indebtedness with an outstanding principal balance of $125 million or more; bankruptcy; judgments involving liability of $125 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Senior Secured Second Lien Notes

In December 2015, we completed private offers to exchange newly issued 8.00% Senior Secured Second Lien Notes due 2022 (Second Lien Notes) for certain outstanding senior unsecured notes and contingent convertible senior notes (Existing Notes). The 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. Chesapeake’s obligations under the Second Lien Notes are fully and unconditionally guaranteed, jointly and severally, by certain of our direct and indirect wholly owned subsidiaries.

Certain of the Existing Notes that were exchanged for the Second Lien Notes were accounted for as a troubled debt restructuring (TDR). For the exchanges classified as a TDR, if the future undiscounted cash flows of the newly issued debt are less than the net carrying value of the original debt, a gain is recorded for the difference and the carrying value of the newly issued debt is adjusted to the future undiscounted cash flow amount and no future interest expense is recorded. All future interest payments on the newly issued debt reduce the carrying value. Accordingly, we recognized a gain of $304 million in our 2015 consolidated statement of operations, and the remaining reduction in principal amount of Existing Notes ($990 million as of December 31, 2016) is included in the carrying value of our Second Lien Notes. As a result, our reported interest expense will be significantly less than the contractual interest payments throughout the term of the Second Lien Notes. For the remaining TDR exchanges, where the future undiscounted cash flows are greater than the net carrying value of the original debt, no gain is recognized and a new effective interest rate is established. For the other Existing Notes that were exchanged that did not qualify as a TDR, we accounted for these exchanges as either a modification or extinguishment. Direct costs incurred of $30 million in 2015 related to the notes exchange were expensed and are included within gains (losses) on purchases or exchanges of debt in our consolidated statement of operations.

Senior Notes, Contingent Convertible Senior Notes and Convertible Senior Notes

The senior notes and the 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. Chesapeake’s obligations under the senior notes and the convertible senior notes are fully and unconditionally guaranteed, jointly and severally, by certain of our direct and indirect wholly owned subsidiaries.

Chesapeake Energy Corporation is a holding company and has no independent assets or operations. Our obligations under our outstanding senior notes and convertible senior notes are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Our non-guarantor subsidiaries are minor and, as such, we have not included condensed consolidating financial information in the notes to our consolidated financial statements.

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 the Company 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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 2.5% Contingent Convertible Senior Notes due 2037, our 2.25% Contingent Convertible Senior Notes due 2038 and our 5.5% Convertible Senior Notes due 2026 are 8.0%, 8.0% and 11.5%, respectively.

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, Chesapeake 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 by Chesapeake.

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.

During 2016, we used the net proceeds from our term loan and convertible and senior notes issuances discussed above, together with cash on hand, to purchase and retire $1.451 billion principal amount of our outstanding senior notes and $708 million principal amount of our outstanding contingent convertible senior notes for an aggregate $2.078 billion pursuant to tender offers.

During 2016, in addition to the repayment upon maturity of $259 million principal amount of our 3.25% Senior Notes due 2016, we repurchased in the open market approximately $325 million principal amount of our outstanding senior notes for $300 million and $141 million principal amount of our outstanding contingent convertible senior notes for $86 million.

Additionally, we privately negotiated exchanges of approximately $290 million principal amount of our outstanding senior notes for 53,923,925 shares of common stock and $287 million principal amount of our outstanding contingent convertible senior notes for 55,427,782 shares of common stock.

For the year ended December 31, 2016, 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.

During 2015, as required by the terms of the indenture for our 2.75% Contingent Convertible Senior Notes due 2035 (the 2035 Notes), the holders were provided the option to require us to purchase on November 15, 2015, all or a portion of the holders’ 2035 Notes at par plus accrued and unpaid interest up to, but excluding, November 15, 2015. On November 16, 2015, we paid an aggregate of approximately $394 million to purchase all of the 2035 Notes that were tendered and not withdrawn. An aggregate of $2 million principal amount of the 2035 Notes remains outstanding as of December 31, 2016.

During 2015, we repurchased in the open market approximately $119 million aggregate principal amount of our 3.25% Senior Notes due 2016 for cash. We recorded a gain of approximately $5 million associated with the repurchase.

During 2014, we issued $3.0 billion in aggregate principal amount of senior notes at par. The offering included two series of notes: $1.5 billion in aggregate principal amount of Floating Rate Senior Notes due 2019 and $1.5 billion in aggregate principal amount of 4.875% Senior Notes due 2022. We used a portion of the net proceeds of $2.966 billion to repay the borrowings under, and terminate, our then-existing term loan credit facility. We used the remaining proceeds along with cash on hand to redeem the remaining $97 million principal amount of the 6.875% Senior Notes

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

due 2018 and to purchase and redeem the remaining $1.265 billion principal amount of the 9.5% Senior Notes due 2015 for $1.454 billion. We recorded a loss of approximately $6 million associated with the redemption of the 6.875% Senior Notes due 2018, which consisted of $5 million in premiums and $1 million of unamortized deferred charges. We recorded a loss of approximately $99 million associated with the purchase and redemption of the 9.5% Senior Notes due 2015, which consisted of $87 million in premiums, $9 million of unamortized discount and $3 million of unamortized deferred charges.

Revolving Credit Facility

We have a $4.0 billion senior secured revolving credit facility (currently subject to a $3.8 billion borrowing base) that matures in December 2019. As of December 31, 2016, we had no outstanding borrowings under the revolving credit facility and had used $1.036 billion of the revolving credit facility for various letters of credit (including the $461 million supersedeas bond with respect to the 2019 Notes litigation discussed in Note 4). 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. We were in compliance with all applicable financial covenants under the agreement as of December 31, 2016.

During 2016, we entered into the third amendment to our revolving credit facility. Pursuant to the amendment, our borrowing base was reaffirmed in the amount of $4.0 billion and the next scheduled borrowing base redetermination review was postponed until June 15, 2017, with the consenting lenders agreeing not to exercise their interim redetermination right prior to that date. Our borrowing base may be reduced if we dispose of a certain percentage of the value of collateral securing the facility. As a result of certain asset sales discussed in Note 12 and certain other sales of collateral since the date of the most recent amendment, our borrowing base was reduced to $3.8 billion as of December 31, 2016. The amendment also provides temporary financial covenant relief, with the revolving credit facility’s existing first lien secured leverage ratio and net debt to capitalization ratio suspended until September 30, 2017 and the interest coverage ratio maintenance covenant reduced as noted below. In addition, we agreed to grant liens and security interests on a majority of our assets, as well as maintain a minimum liquidity amount (defined as cash and cash equivalents and availability under our revolving credit facility) of $500 million until the suspension of the existing maintenance covenants ends.

The amendment reduces the interest coverage ratio from 1.1 to 1.0 to 0.65 to 1.0 through the first quarter of 2017, after which it will increase to 0.70 to 1.0 for the second quarter of 2017, 1.2 to 1.0 for the third quarter of 2017 and 1.25 to 1.0 thereafter. The amendment also includes a collateral value coverage test whereby if the collateral value coverage ratio, tested as of December 31, 2016, falls below 1.1 to 1.0, the $500 million minimum liquidity covenant increases to $750 million, and if the collateral value coverage ratio, tested as of March 31, 2017, falls below 1.25 to 1.0, our borrowing ability will be reduced in order to satisfy such ratio. The amendment also gives us the ability to incur up to $2.5 billion of first lien indebtedness secured 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. After taking into account the term loan, the amount of additional first lien indebtedness permitted by the revolving credit facility is $1.0 billion.

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, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			($ in millions)
Short-term debt (Level 1)	$	503	$	511	$	381	$	366
Long-term debt (Level 1)	$	3,271	$	3,216	$	6,720	$	2,546
Long-term debt (Level 2)	$	6,664	$	6,654	$	3,584	$	1,189

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


4.	Contingencies and Commitments

Contingencies

Litigation and Regulatory Proceedings

The Company is 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. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different. Our total estimated 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. We account for legal defense costs in the period the costs are incurred.

2016 Shareholder Litigation. On April 19, 2016, a shareholder lawsuit was filed in the U.S. District Court for the Western District of Oklahoma against the Company and current and former directors and officers of the Company alleging, among other things, violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act, breach of fiduciary duties, waste of corporate assets, gross mismanagement and violations of Sections 10(b) and Rule 10b-5 of the Exchange Act related to actions allegedly taken by such persons since 2008. The lawsuit sought to assert derivative and direct claims, certification as a class action, damages, attorneys’ fees and other costs. The District Court dismissed the plaintiffs’ claims on August 30, 2016.

Regulatory and Related Proceedings. The Company has received, from the U.S. Department of Justice (DOJ) and certain state governmental agencies and authorities, subpoenas and demands for documents, information and testimony in connection with investigations into possible violations of federal and state antitrust laws relating to our purchase and lease of oil and natural gas rights in various states. The Company also has received DOJ, U.S. Postal Service and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake has engaged in discussions with the DOJ, U.S. Postal Service and state agency representatives and continues to respond to such subpoenas and demands.

In addition, the Company received a DOJ subpoena and a voluntary document request from the SEC seeking information on our accounting methodology for the acquisition and classification of oil and natural gas properties and related matters. Chesapeake has engaged in discussions with the DOJ and SEC about these matters. On October 4, 2016, a securities class action was filed in the U.S. District Court for the Western District of Oklahoma against the Company and certain current directors and officers of the Company alleging, among other things, violations of federal securities laws for purported misstatements in the Company’s SEC filings and other public disclosures regarding the Company’s accounting for the acquisition and classification of oil and natural gas properties. The lawsuit seeks certification as a class action, damages, attorneys’ fees and other costs.

Redemption of 2019 Notes. As previously disclosed in the 2015 Form 10-K, in connection with the litigation related to the Company’s notice issued on March 15, 2013, to redeem all of the 2019 Notes at par (plus accrued interest through the redemption date) pursuant to the special early redemption provision of the supplemental indenture governing the 2019 Notes, the Company filed a notice of appeal on July 27, 2015, of an amended judgment entered on July 17, 2015, by the U.S. District Court for the Southern District of New York awarding the Trustee for the 2019 Notes $380 million plus prejudgment interest in the amount of $59 million. The Company posted a supersedeas bond in the amount of $461 million (reflected as an outstanding letter of credit under the Company’s revolving credit facility) to stay execution of the judgment while appellate proceedings are pending. The Company accrued a loss contingency of $100 million for this matter in 2014 and an additional $339 million in 2015. On September 15, 2016, the United States Court of Appeals for the Second Circuit affirmed the trial court’s ruling. On February 2, 2017, the Company filed a petition for writ of certiorari with the United States Supreme Court seeking review of the Court of Appeals’ decision.

Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. With regard to contract actions, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their oil and natural gas interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The Company has successfully defended a number of these failure-to-close cases in various courts and has settled and resolved other such cases and disputes.

Regarding royalty claims, Chesapeake 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, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. 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. The Company has 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 lawsuits seeking damages with respect to royalty underpayment in various states, including, but not limited to, Texas, Pennsylvania, Ohio, Oklahoma, Kentucky, Louisiana and Arkansas. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The Company also has received DOJ, U.S. Postal Service and state subpoenas or information requests seeking information on the Company’s royalty payment practices.

Chesapeake is defending numerous lawsuits filed by individual royalty owners alleging royalty underpayment with respect to properties in Texas. These lawsuits, organized for pre-trial proceedings with respect to the Barnett Shale and Eagle Ford Shale, respectively, generally allege that Chesapeake underpaid royalties by making improper deductions, using incorrect production volumes and similar theories. Chesapeake expects that additional lawsuits will continue to be pursued and that new plaintiffs will file other lawsuits making similar allegations.

On December 9, 2015, the Commonwealth of Pennsylvania, through 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 Chesapeake 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 Chesapeake is a party established unlawful market allocation for the acquisition of leases. The lawsuit seeks statutory restitution, civil penalties and costs, as well as temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid and permanent injunction from further violations of the UTPCPL. Chesapeake has filed preliminary objections to the most recently amended complaint.

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 Company’s divestiture of substantially all of its midstream business and most of its 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. One of the cases includes claims of intentional interference with contractual relations and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources.

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.

The Company is 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 United States District Court for the Western District of Oklahoma and in Oklahoma state courts, and an individual lawsuit was filed in the United States District Court of Kansas, in each case against the Company 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 which would restrain competition in a similar manner as alleged in the lawsuits.

Other Matters

In April 2016, a class action lawsuit on behalf of holders of the Company’s 6.875% Senior Notes due 2020 (the 2020 Notes) and 6.125% Senior Notes due 2021 (2021 Notes) was filed in the U.S. District Court for the Southern District of New York relating to the Company’s December 2015 debt exchange, whereby the Company privately exchanged newly issued 8.00% Senior Secured Second Lien Notes due 2022 (Second Lien Notes) for certain outstanding senior unsecured notes and contingent convertible notes. The lawsuit alleges that the Company violated the Trust Indenture Act of 1939 and the implied covenant of good faith and fair dealing by benefiting themselves and a minority of noteholders who are qualified institutional buyers (QIBs). According to the lawsuit, as a result of the Company’s private debt exchange in which only QIBs (and non-U.S. persons under Regulation S) were eligible to participate, the Company unjustly enriched itself at the expense of class members by reducing indebtedness and reducing the value of the 2020 Notes and the 2022 Notes. The lawsuit seeks damages and attorney’s fees, in addition to declaratory relief that the debt exchange and the liens created for the benefit of the Second Lien Notes are null and void and that the debt exchange effectively resulted in a default under the indentures for the 2020 Notes and the 2021 Notes. In June 2016, the lawsuit was transferred to the United States District Court for the Western District of Oklahoma, and in October 2016, the Company filed a motion to dismiss for failure to state a claim. The District Court dismissed the plaintiffs’ claims on February 8, 2017.

Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to the Company’s business operations is likely to have a material adverse effect on its 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.

Environmental Contingencies

The nature of the oil and gas business carries with it certain environmental risks for Chesapeake and its subsidiaries. Chesapeake has implemented various policies, programs, procedures, training and auditing to reduce and mitigate such environmental risks. Chesapeake conducts 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, Chesapeake 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.

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, 2016
	($ in millions)
2017	$	4
2018	3
2019	2
Total	$	9

Lease expense for the years ended December 31, 2016, 2015 and 2014, was $5 million, $7 million and $33 million, respectively. Lease expense decreased significantly in 2016 and 2015 compared to 2014 primarily due to the repurchase of all rigs and compressors previously sold under long-term sale-leaseback arrangements.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 proportionate share of these costs 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, 2016
	($ in millions)
2017	$	1,434
2018	1,229
2019	1,178
2020	1,074
2021	970
2022 – 2099	5,225
Total	$	11,110

In addition to the above commitments, 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 vary with the applicable agreement.

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, 2016, the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below.



	December 31, 2016
	($ in millions)
2017	$	91
2018	14
Total	$	105

Pressure Pumping Contracts

We have an agreement for pressure pumping services, which expires in June 2017. The services agreement requires us to utilize, at market-based pricing, the lesser of (i) three pressure pumping crews through June 30, 2017, or (ii) 50% of the total number of all pressure pumping crews working for us in all of our operating regions during the respective year. We are also required to utilize the pressure pumping services for a minimum number of fracture stages as set forth in the agreement. We are entitled to terminate the agreement in certain situations, including if the contractor fails to provide the overall quality of service provided by similar service providers. These commitments are not recorded as obligations in the accompanying consolidated balance sheets. As of December 31, 2016, the aggregate undiscounted minimum future payments under this agreement were approximately $53 million.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 volumetric production payment (VPP) transactions. 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.

Net Acreage Maintenance Commitments

Under the terms of our Utica Shale joint venture agreements with Total S.A., we are required to extend, renew or replace expiring joint leasehold, at our cost, to ensure that the net acreage maintenance level is met as of the December 31, 2017 measurement date.

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 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, 2016 and 2015 are detailed below.



	December 31,
	2016		2015
	($ in millions)
Revenues and royalties due others	$	543	$	500
Accrued drilling and production costs	169		212
Joint interest prepayments received	71		169
Accrued compensation and benefits	239		264
Other accrued taxes	32		37
Bank of New York Mellon legal accrual	440		439
Minimum gathering volume commitment	—		201
Other	304		397
Total other current liabilities	$	1,798	$	2,219

Other long-term liabilities as of December 31, 2016 and 2015 are detailed below.



	December 31,
	2016		2015
	($ in millions)
CHK Utica ORRI conveyance obligation(a)	$	160	$	190
Financing obligations	—		29
Unrecognized tax benefits	97		64
Other	126		126
Total other long-term liabilities	$	383	$	409


(a)	Approximately $43 million and $21 million of the total $203 million and $211 million obligations are recorded in other current liabilities as of December 31, 2016 and 2015, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction.

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,
	2016			2015			2014
	($ in millions)
Current
Federal	$	(14	)	$	—		$	—
State	(5		)	(36		)	47
Current Income Taxes	(19		)	(36		)	47
Deferred
Federal	(147		)	(4,385		)	1,115
State	(24		)	(42		)	(18		)
Deferred Income Taxes	(171		)	(4,427		)	1,097
Total	$	(190	)	$	(4,463	)	$	1,144

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,
	2016			2015			2014
	($ in millions)
Income tax expense (benefit) at the federal statutory rate (35%)	$	(1,606	)	$	(6,684	)	$	1,120
State income taxes (net of federal income tax benefit)	(30		)	(406		)	68
Remeasurement of state deferred tax liabilities	—			—			(114		)
Change in valuation allowance	1,423			2,727			74
Other	23			(100		)	(4		)
Total	$	(190	)	$	(4,463	)	$	1,144

In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of $190 million of tax benefit to continuing operations. This tax benefit was partially offset by $165 million of tax expense and $10 million of tax benefit associated with the equity components of the debt transactions that occurred during the year. See Note 3 for further discussion of our debt transactions. Additionally, $4 million of tax expense was allocated to other comprehensive income. The result is a net tax benefit of $31 million which is primarily due to tax elections that allow for realization of deferred tax assets related to alternative minimum tax (AMT) credits.

We reassessed the realizability of our deferred tax assets given the low commodity prices and recorded a $1.423 billion increase in our valuation allowance in our consolidated statement of operations for the year ended December 31, 2016. The increase in the valuation allowance is to offset the portion of the tax benefit at expected rates that we believe is more likely than not to not be realized.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:



	Years Ended December 31,
	2016			2015
	($ in millions)
Deferred tax liabilities:
Volumetric production payments	$	(223	)	$	(802	)
Derivative instruments	—			(300		)
Other	(62		)	(71		)
Deferred tax liabilities	(285		)	(1,173		)

Deferred tax assets:
Property, plant and equipment	593			1,144
Net operating loss carryforwards	2,587			1,556
Carrying value of debt	539			532
Asset retirement obligations	98			174
Investments	275			260
Derivative instruments	161			—
Accrued liabilities	319			333
Other	118			123
Deferred tax assets	4,690			4,122
Valuation allowance	(4,389		)	(2,949		)
Net deferred tax assets	301			1,173
Net deferred tax assets(a)	$	16		$	—


(a)	The net deferred tax assets are included in other long-term assets in the accompanying balance sheets.

As of December 31, 2016, Chesapeake had federal income tax NOL carryforwards of approximately $6.2 billion and state NOL carryforwards of approximately $9.5 billion which excludes the NOL carryforwards related to unrecognized tax benefits. The associated deferred tax assets related to these NOL carryforwards were $2.161 billion and $426 million, respectively. The NOL carryforwards expire between 2031 and 2036. The value of these carryforwards depends on the ability of Chesapeake to generate taxable income. As of December 31, 2016 and 2015, we had deferred tax assets of $4.690 billion and $4.122 billion upon which we had a valuation allowance of $4.389 billion and $2.949 billion, respectively. Of the net change in the valuation allowance of $1.440 billion for both federal and state deferred tax assets, $1.423 billion is reflected as a component of income tax expense in the consolidated statement of operations and $17 million is reflected as a component of equity.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all 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. As of December 31, 2016, we believe it is more likely than not that these deferred tax assets will not be realized. Management assesses the 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 objective negative evidence evaluated is the cumulative loss incurred over the three-year period ending December 31, 2016. Such objective negative evidence limits the ability to consider other subjective positive evidence, such as our projections for future growth. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future expected growth.

The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended. 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 the 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, 2016, we do not believe that an ownership change has occurred that would limit our NOL carryforwards. Future equity transactions by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs.

Accounting guidance for recognizing and measuring uncertain tax positions prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to 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, 2016 and 2015, the amount of unrecognized tax benefits related to NOL carryforwards and state tax liabilities associated with uncertain tax positions was $202 million and $280 million, respectively. Of the 2016 amount, $76 million is related to state tax liabilities while the remainder is related to NOL carryforwards. Of the 2015 amount, $44 million is related to state tax liabilities while the remainder is related to NOL carryforwards. The uncertain tax positions identified would not have a material effect on the effective tax rate. No material changes to the current uncertain tax positions are expected within the next 12 months. As of both December 31, 2016 and 2015, we had accrued liabilities of $20 million for interest related to these uncertain tax positions. Chesapeake recognizes interest related to uncertain tax positions in 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:



	2016			2015			2014
	($ in millions)
Unrecognized tax benefits at beginning of period	$	280		$	303		$	644
Additions based on tax positions related to the current year	—			27			13
Additions to tax positions of prior years	33			—			—
Settlements	(111		)	—			—
Reductions to tax positions of prior years	—			(50		)	(354		)
Unrecognized tax benefits at end of period	$	202		$	280		$	303

Chesapeake's 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. The 2010 through 2016 years and the 2007 through 2016 years remain open for all purposes of examination by the IRS and other taxing authorities in material jurisdictions, respectively.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


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 FTS International, Inc. (FTS). 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, 2016, 2015 and 2014, our expenditures for hydraulic fracturing services with FTS were $3 million, $65 million and $220 million, respectively.


8.	Equity

Common Stock

A summary of the changes in our common shares issued for the years ended December 31, 2016, 2015 and 2014 is detailed below.



	Years Ended December 31,
	2016	2015		2014
	(in thousands)
Shares issued as of January 1	664,796	664,944		666,192
Exchange of convertible notes	55,428	—		—
Exchange of senior notes	53,924	—		—
Conversion of preferred stock	120,186	—		—
Restricted stock issuances (net of forfeitures and cancellations)(a)	1,945	(163	)	(2,529	)
Stock option exercises	—	15		1,281
Shares issued as of December 31	896,279	664,796		664,944


(a)	The amount for 2014 reflects forfeitures upon the June 2014 spin-off of our oilfield services business.

During the year ended December 31, 2016, our shareholders approved an amendment to our certificate of incorporation to increase our authorized common stock from 1,000,000,000 shares to 1,500,000,000 shares, par value $0.01 per share.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Preferred Stock

Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2016:



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	$	32.7572

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


(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.

Outstanding shares of our preferred stock for the years ended December 31, 2016, 2015 and 2014 are detailed below.



	5.75%		5.75% (A)		4.50%	5.00% (2005B)
	(in thousands)
Shares outstanding as of January 1, 2016	1,497		1,100		2,559	2,096
Preferred stock conversions/exchanges(a)	(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

Shares outstanding as of January 1, 2014 and December 31, 2014	1,497		1,100		2,559	2,096

(a)

During 2016, holders of our 5.75% Cumulative Convertible Preferred Stock exchanged or converted 653,872 shares into 59,141,429 shares of common stock, holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock exchanged or 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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Dividends

In January 2016, we announced that we were suspending dividend payments on each series of our outstanding convertible preferred stock. Suspension of the dividends did not constitute an event of default under our revolving credit facility or bond indentures. Our preferred stock dividends for the year ended December 31, 2016 (paid in arrears) are detailed below.



	5.75%		5.75% (A)		4.50%		5.00% (2005B)
	($ in millions)
Dividends in arrears	$	48	$	27	$	12	$	10

On February 15, 2017, we reinstated the payment of dividends on each series of our outstanding convertible preferred stock and paid our dividends in arrears.

Accumulated Other Comprehensive Income (Loss)

For the years ended December 31, 2016 and 2015, changes in accumulated other comprehensive income (loss) for cash flow hedges, net of tax, are detailed below.



	Years Ended December 31,
	2016			2015
	($ in millions)
Balance, beginning of period	$	(99	)	$	(143	)

Other comprehensive income before reclassifications	(13		)	20
Amounts reclassified from accumulated other comprehensive income	16			24
Net other comprehensive income (loss)	3			44

Balance, end of period	$	(96	)	$	(99	)

For the years ended December 31, 2016 and 2015, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statements of operations are detailed below.



Details About Accumulated Other Comprehensive Income (Loss) Components	Affected Line Item in the Statement Where Net Income is Presented	Amounts Reclassified
		($ in millions)
Year Ended December 31, 2016
Net losses on cash flow hedges:
Commodity contracts	Oil, natural gas and NGL revenues	$	16
Foreign currency derivative	Gain (loss) on purchases or exchanges of debt	—
Total reclassifications for the period, net of tax		$	16

Year Ended December 31, 2015
Net losses on cash flow hedges:
Commodity contracts	Oil, natural gas and NGL revenues	$	23
Foreign currency derivative	Gain (loss) on purchases or exchanges of debt	1
Total reclassifications for the period, net of tax		$	24

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Noncontrolling Interests

Cleveland Tonkawa Financial Transaction. We formed CHK C-T in March 2012 to continue development of a portion of our oil and natural gas assets in our Cleveland and Tonkawa plays. In March 2012, in a private placement, 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. We initially committed to drill and complete, for the benefit of CHK C-T in the area of mutual interest, a minimum cumulative total of 300 net wells. We ultimately drilled and completed 190 net wells, and the drilling commitment was suspended in January 2015.

During 2015, CHK C-T sold all of its oil and natural gas properties to FourPoint Energy, LLC and immediately used the consideration received, plus other cash it had on hand, to repurchase and cancel all of the outstanding preferred shares in CHK C-T. In connection with the repurchase and cancellation of the CHK C-T preferred stock and related agreements with the CHK C-T investors, we eliminated quarterly preferred dividend payments and all related future drilling and ORRI commitments attributable to CHK C-T. The sale of the oil and natural gas properties was accounted for as a reduction of capitalized costs with no gain or loss recognized.

For 2015 and 2014, income of $50 million and $75 million, respectively, was attributable to the noncontrolling interests of CHK C-T.

Utica Financial Transaction. We formed CHK Utica, L.L.C. (CHK Utica) in October 2011 to develop a portion of our Utica Shale oil and natural gas assets. During November and December 2011, in private placements, third-party investors contributed $1.25 billion in cash to CHK Utica in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3% ORRI in 1,500 net wells to be drilled on certain of our Utica Shale leasehold.

In July 2014, we repurchased all of the outstanding preferred shares of CHK Utica from third-party preferred shareholders for approximately $1.254 billion, or approximately $1,189 per share including accrued dividends. The $447 million difference between the cash paid for the preferred shares and the carrying value of the noncontrolling interest acquired was reflected in retained earnings and as a reduction to net income available to common stockholders for purposes of our EPS computations. Pursuant to the transaction, our obligation to pay quarterly dividends to third-party preferred shareholders was eliminated. In addition, the development agreement was terminated pursuant to the transaction, which eliminated our obligation to drill and complete a minimum number of wells within a specified period for the benefit of CHK Utica. Our repurchase of the outstanding preferred shares in CHK Utica did not affect our obligation to deliver a 3% ORRI in 1,500 net wells on certain of our Utica Shale leasehold.

The CHK Utica investors’ right to receive, proportionately, a 3% ORRI in the first 1,500 net wells drilled on certain of our Utica Shale leasehold is subject to an increase to 4% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs through 2023. However, in no event are we required to deliver to investors more than a total ORRI of 3% in 1,500 net wells. If at any time we hold fewer net acres than would enable us to drill all then-remaining net wells on 150-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. We retain the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 1,300 net wells. As of December 31, 2016, we had drilled 508 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the future conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. We met our ORRI conveyance commitments as of December 31, 2014 and 2015 but did not meet our commitment in 2016. The ORRI will increase to 4% for wells drilled in 2017.

In 2014, income of approximately $43 million was attributable to the noncontrolling interests of CHK Utica.

Chesapeake Granite Wash Trust. In November 2011, Chesapeake Granite Wash Trust (the Trust) sold 23,000,000 common units representing beneficial interests in the Trust at a price of $19.00 per common unit in its initial public offering. The common units are listed on the New York Stock Exchange and trade under the symbol “CHKR”. We own 12,062,500 common units and 11,687,500 subordinated units, which in the aggregate represent an approximate 51% beneficial interest in the Trust. The Trust has a total of 46,750,000 units outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The subordinated units we hold in the Trust are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is not less than the applicable subordination threshold for the quarter. If there is not sufficient cash to fund a distribution on all of the Trust units, the distribution to be made with respect to the subordinated units is reduced or eliminated for the quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. The distribution made with respect to the subordinated units to Chesapeake was either reduced or eliminated for each of the most recent 18 quarters. In exchange for agreeing to subordinate a portion of our Trust units, and in order to provide additional financial incentive to us to perform operations on the underlying properties in an efficient and cost-effective manner, Chesapeake is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on the Trust units in any quarter exceeds the applicable incentive threshold for the quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold is to be paid to Trust unitholders, including Chesapeake, on a pro rata basis. Through December 31, 2016, no incentive distributions had been made. At the end of the 2017 second quarter, the subordinated units will automatically convert into common units on a one-for-one basis and our right to receive incentive distributions will terminate. After this time, the common units will no longer have the protection of the subordination threshold, and all Trust unitholders will share in the Trust’s distributions on a pro rata basis.

For the years ended December 31, 2016, 2015 and 2014, the Trust declared and paid the following distributions:



Production Period	Distribution Date	Cash Distribution per Common Unit		Cash Distribution per Subordinated Unit
June 2016 – August 2016	December 1, 2016	$	0.0857	$	—
March 2016 – May 2016	August 29, 2016	$	0.0734	$	—
December 2015 – February 2016	May 31, 2016	$	0.0403	$	—
September 2015 – November 2015	March 1, 2016	$	0.2195	$	—
June 2015 – August 2015	November 30, 2015	$	0.3232	$	—
March 2015 – May 2015	August 31, 2015	$	0.3579	$	—
December 2014 – February 2015	June 1, 2015	$	0.3899	$	—
September 2014 – November 2014	March 2, 2015	$	0.4496	$	—
June 2014 – August 2014	December 1, 2014	$	0.5079	$	—
March 2014 – May 2014	August 29, 2014	$	0.5796	$	—
December 2013 – February 2014	May 30, 2014	$	0.6454	$	—
September 2013 – November 2013	March 3, 2014	$	0.6624	$	—

We have determined that the Trust is a variable interest entity (VIE) and that Chesapeake is the primary beneficiary. As a result, the Trust is included in our consolidated financial statements. As of December 31, 2016 and 2015, we had $257 million and $259 million, respectively, of noncontrolling interests on our consolidated balance sheets attributable to the Trust. Net income attributable to the Trust’s noncontrolling interest is presented in our consolidated statements of operations as $2 million for the year ended December 31, 2016, a nominal amount for the year ended December 2015 and $24 million for the year ended December 31, 2014. See Note 15 for further discussion of VIEs.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


9.	Share-Based Compensation

Chesapeake’s 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. In connection with the spin-off of our oilfield services business on June 30, 2014, and pursuant to the terms of our share-based compensation plans and the employee matters agreement between Chesapeake and Seventy Seven Energy Inc. (SSE), unexercised stock options and unvested restricted stock were modified as of the date of the spin-off. The modifications were designed to ensure that the value of each award of unexercised stock options and unvested restricted stock did not change as a result of the spin-off. The number of stock options and number of shares of restricted stock reported below have been adjusted to reflect modifications on the spin-off date.

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 withhold 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, 2016, 61,856,065 shares of common stock remained issuable under the 2014 LTIP.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Equity-Classified Awards

Restricted Stock. We grant restricted stock units to employees and non-employee directors. Prior to 2014, we also granted restricted stock awards as equity compensation. We refer to both types of awards as restricted stock. A summary of the changes in unvested restricted stock during 2016, 2015 and 2014 is presented below.



	Shares of Unvested Restricted Stock		Weighted Average Grant Date Fair Value
	(in thousands)
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

Unvested restricted stock as of January 1, 2014	13,400		$	23.38
Granted	5,049		$	25.92
Vested	(4,803	)	$	27.17
Forfeited	(3,555	)	$	28.09
Unvested restricted stock as of December 31, 2014	10,091		$	21.20

The aggregate intrinsic value of restricted stock that vested during 2016 was approximately $21 million based on the stock price at the time of vesting.

As of December 31, 2016, there was approximately $50 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 1.5 years.

Stock Options. In 2016, 2015 and 2014, we granted members of senior 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 the Company’s common stock on the grant date. Outstanding options expire seven 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 the Company's 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 2016.



Expected option life – years	6.0
Volatility	46.07	%
Risk-free interest rate	1.70	%
Dividend yield	—	%

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table provides information related to stock option activity for 2016, 2015 and 2014.



	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, 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	$	—

Outstanding as of January 1, 2014	5,268		$	19.28	6.66	$	41
Granted	994		$	24.43
Exercised	(1,322	)	$	18.71		$	11
Expired	(28	)	$	18.97
Forfeited	(313	)	$	21.05
Outstanding as of December 31, 2014	4,599		$	19.55	7.03	$	5

Exercisable as of December 31, 2014	1,304		$	18.71	5.70	$	1


(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, 2016, there was $7 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 1.70 years.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, 2016, 2015 and 2014.



	Years Ended December 31,
	2016		2015		2014
	($ in millions)
General and administrative expenses	$	38	$	43	$	46
Oil and natural gas properties	16		23		29
Oil, natural gas and NGL production expenses	13		18		18
Marketing, gathering and compression expenses	1		5		6
Oilfield services expenses	—		—		5
Total	$	68	$	89	$	104

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 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%. For PSUs granted in 2014, the TSR component can range from 0% to 200%, with no operational components. 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 the Company’s estimates of the underlying performance measures. The Company utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the PSUs. The payout percentage for all PSU grants is capped at 100% if the Company's absolute TSR is less than zero.



Volatility	91.19	%
Risk-free interest rate	1.20	%
Dividend yield for value of awards	—	%

The following table presents a summary of our 2016, 2015 and 2014 PSU awards.



		Grant Date Fair Value		December 31, 2016
	Units		Fair Value		Vested Liability
		($ in millions)
2016 Awards:
Payable 2019	2,348,893	$	10	$	20	$	12
2015 Awards:
Payable 2018	629,694	$	13	$	4	$	3
2014 Awards:
Payable 2017	561,215	$	16	$	—	$	—

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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



	Years Ended December 31,
	2016		2015			2014
	($ in millions)
General and administrative expenses	$	14	$	(19	)	$	(4	)
Restructuring and other termination costs	1		(19		)	(19		)
Marketing, gathering and compression	—		(1		)	—
Oil and natural gas properties	—		(2		)	3
Total	$	15	$	(41	)	$	(20	)

Effect of the Spin-off on Share-Based Compensation

The employee matters agreement entered into in connection with the June 2014 spin-off of our oilfield services business (see Note 13) addresses the treatment of holders of Chesapeake stock options, restricted stock and PSUs that were impacted by the spin-off. Unvested equity-based compensation awards held by Chesapeake Oilfield Operating, L.L.C. (COO) employees were canceled and replaced with new awards of SSE, and unvested equity-based compensation awards held by Chesapeake employees were adjusted to account for the spin-off, each as of the spin-off date. The employee matters agreement provides that employees of SSE ceased to participate in benefit plans sponsored or maintained by Chesapeake as of the spin-off date. In addition, the employee matters agreement provides that as of the spin-off date, each party is responsible for the compensation of its current employees and for all liabilities relating to its former employees, as determined by their respective employer on the date of termination.

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. Through December 31, 2014, Chesapeake matched employee contributions dollar for dollar (subject to a maximum contribution of 15% of an employee's base salary and performance bonus) with Chesapeake common stock purchased in the open market. Beginning January 1, 2015, Chesapeake matched employee contributions in cash. The Company contributed $39 million, $52 million and $61 million to the 401(k) Plan in 2016, 2015 and 2014, respectively.

Chesapeake also maintains 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 Company wage earners are eligible to participate. Additionally, the employee had to have made the maximum contribution allowable under the 401(k) Plan. Chesapeake matches 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 Company deferred compensation plans, including the Chesapeake 401(k) Plan, is a total of 75% of base salary and 100% of performance bonus. The Company contributed $9 million, $11 million and $7 million to the DC Plan during 2016, 2015 and 2014, 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 Chesapeake to fund future obligations of the Company's 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

Chesapeake uses derivative instruments to secure attractive pricing and margins on its share of expected production, to reduce its exposure to fluctuations in future commodity prices and to protect its expected operating cash flow against significant market movements or volatility. Chesapeake also uses derivative instruments to mitigate a portion of its exposure to foreign currency exchange rate fluctuations. All of our commodity 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.

Oil, Natural Gas and NGL Derivatives

As of December 31, 2016 and 2015, our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:


•	Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we granted options that allow the counterparty to double the notional amount.

•

Options: Chesapeake sells, 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, Chesapeake pays the counterparty the excess on sold call options and Chesapeake receives 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.


•	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, Chesapeake receives 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.


•	Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. Chesapeake receives 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, 2016 and 2015 are provided below.



	December 31, 2016				December 31, 2015
	Volume	Fair Value			Volume	Fair Value
		($ in millions)				($ in millions)
Oil (mmbbl):
Fixed-price swaps	23	$	(140	)	14	$	144
Call options	5	(1		)	19	(7		)
Total oil	28	(141		)	33	137

Natural gas (tbtu):
Fixed-price swaps	719	(349		)	500	229
Collars	60	(9		)	—	—
Call options	114	—			295	(99		)
Basis protection swaps	31	(5		)	57	—
Total natural gas	924	(363		)	852	130

NGL (mmgal):
Fixed-price swaps	53	—			—	—

Total estimated fair value		$	(504	)		$	267

We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. See further discussion below under Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss).

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Interest Rate Derivatives

As of December 31, 2016 and 2015, there were no interest rate derivatives outstanding.

We have terminated fair value hedges related to certain of our senior notes. Gains and losses related to these terminated hedges will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next four years, we will recognize $3 million in net gains related to these transactions.

Foreign Currency Derivatives

We are party to cross currency swaps to mitigate our exposure to foreign currency exchange rate fluctuations. During 2016, in connection with debt repurchases, we retired €56 million in aggregate principal amount of our 6.25% Euro-denominated Senior Notes due 2017, and we simultaneously unwound the cross currency swaps for the same principal amount at a cost of $13 million. Under the terms of the remaining cross currency swaps, on each semi-annual interest payment date, the counterparties pay us €8 million and we pay the counterparties $12 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay us €246 million and we will pay 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 are designated as cash flow hedges and, because they are 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 do not impact earnings. The fair values of the cross currency swaps are recorded on the consolidated balance sheets as liabilities of $73 million and $52 million as of December 31, 2016 and 2015, respectively. The euro-denominated debt in long-term debt has been adjusted to $258 million as of December 31, 2016, using an exchange rate of $1.0517 to €1.00.

Supply Contract Derivatives

From time to time and in the normal course of business, our marketing subsidiary enters into supply contracts under which we commit to deliver a predetermined quantity of natural gas to certain counterparties in an attempt to earn attractive margins. Under certain contracts, we receive a sales price that is based on the price of a product other than natural gas, thereby creating an embedded derivative requiring bifurcation. In one of these supply contracts, we were committed to supply a minimum of 90 bbtu per day of natural gas through March 2025. In 2016, we sold the 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. Concurrent with this sale, we reversed the cumulative unrealized gains associated with this supply contract of $280 million.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, 2016 and 2015 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 Consolidated Balance Sheet
	($ in millions)
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	)

As of December 31, 2015
Commodity Contracts:
Short-term derivative asset	$	381		$	(66	)	$	315
Short-term derivative liability	(106		)	66			(40		)
Long-term derivative liability	(8		)	—			(8		)
Total commodity contracts	267			—			267
Foreign Currency Contracts:(a)
Long-term derivative liability	(52		)	—			(52		)
Total foreign currency contracts	(52		)	—			(52		)
Supply Contracts:
Short-term derivative asset	51			—			51
Long-term derivative asset	246			—			246
Total supply contracts	297			—			297
Total derivatives	$	512		$	—		$	512


(a)	Designated as cash flow hedging instruments.

As of December 31, 2016 and 2015, 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, 2016, 2015 and 2014 are presented below.



	Years Ended December 31,
	2016			2015			2014
	($ in millions)
Oil, natural gas and NGL revenues	$	3,866		$	4,767		$	9,336
Gains (losses) on undesignated oil, natural gas and NGL derivatives	(545		)	661			1,055
Losses on terminated cash flow hedges	(33		)	(37		)	(37		)
Total oil, natural gas and NGL revenues	$	3,288		$	5,391		$	10,354

The components of marketing, gathering and compression revenues for the years ended December 31, 2016, 2015 and 2014 are presented below.



	Years Ended December 31,
	2016			2015		2014
	($ in millions)
Marketing, gathering and compression revenues	$	4,881		$	7,077	$	12,224
Gains (losses) on undesignated supply contract derivatives	(297		)	296		1
Total marketing, gathering and compression revenues	$	4,584		$	7,373	$	12,225

The components of interest expense for the years ended December 31, 2016, 2015 and 2014 are presented below.



	Years Ended December 31,
	2016			2015			2014
	($ in millions)
Interest expense on senior notes	$	588		$	682		$	704
Interest expense on term loan	46			—			36
Amortization of loan discount, issuance costs and other	33			62			42
Amortization of premium associated with troubled debt restructuring	(165		)	(3		)	—
Interest expense on revolving credit facilities	35			12			28
Gains on terminated fair value hedges	(2		)	(3		)	(3		)
(Gains) losses on undesignated interest rate derivatives	12			(9		)	(81		)
Capitalized interest	(251		)	(424		)	(637		)
Total interest expense	$	296		$	317		$	89

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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,
	2016						2015						2014
	Before Tax			After Tax			Before Tax			After Tax			Before Tax			After Tax
	($ in millions)
Balance, beginning of period	$	(160	)	$	(99	)	$	(231	)	$	(143	)	$	(269	)	$	(167	)
Net change in fair value	(27		)	(13		)	32			20			1			1
Losses reclassified to income	34			16			39			24			37			23
Balance, end of period	$	(153	)	$	(96	)	$	(160	)	$	(99	)	$	(231	)	$	(143	)

Approximately $97 million of the accumulated other comprehensive loss as of December 31, 2016 represents the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. Deferred gain or loss amounts will be recognized in earnings in the month in which the originally forecasted hedged production occurs. As of December 31, 2016, we expect to transfer approximately $22 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 rated investment grade 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, 2016, our oil, natural gas and NGL and foreign currency derivative instruments were spread among 12 counterparties.

Hedging Arrangements

In 2015, we began entering into bilateral hedging agreements. The counterparties’ and our obligations under certain of 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. In 2016, certain of our counterparties that are also lenders (or affiliates of our lenders) under our revolving credit facility entered into derivative contracts to be secured by the same collateral that secures the revolving credit facility. This allows us to reduce any letters of credit posted as security with those counterparties.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, interest rate 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, 2016 and 2015:



	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, 2016
Derivative Assets (Liabilities):
Commodity assets	$	—	$	1		$	—		$	1
Commodity liabilities	—		(495		)	(10		)	(505		)
Foreign currency liabilities	—		(73		)	—			(73		)
Total derivatives	$	—	$	(567	)	$	(10	)	$	(577	)

As of December 31, 2015
Derivative Assets (Liabilities):
Commodity assets	$	—	$	372		$	9		$	381
Commodity liabilities	—		(14		)	(100		)	(114		)
Foreign currency liabilities	—		(52		)	—			(52		)
Supply contract assets	—		—			297			297
Total derivatives	$	—	$	306		$	206		$	512

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2016 and 2015 is presented below.



	Commodity Derivatives			Supply Contracts
	($ in millions)
Beginning balance as of December 31, 2015	$	(91	)	$	297
Total gains (losses) (realized/unrealized):
Included in earnings(a)	6			(118		)
Total purchases, issuances, sales and settlements:
Settlements	75			(33		)
Sales	—			(146		)
Ending balance as of December 31, 2016	$	(10	)	$	—

Beginning balance as of December 31, 2014	$	(54	)	$	1
Total gains (losses) (realized/unrealized):
Included in earnings(a)	100			316
Total purchases, issuances, sales and settlements:
Settlements	(137		)	(20		)
Ending balance as of December 31, 2015	$	(91	)	$	297



(a)	Oil, Natural Gas and NGL Sales					Marketing, Gathering and Compression Revenue

	2016			2015		2016			2015
	($ in millions)
Total gains (losses) included in earnings for the period	$	6		$	100	$	(118	)	$	316
Change in unrealized gains (losses) related to assets still held at reporting date	$	(7	)	$	43	$	—		$	296

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, 2016:



Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value December 31, 2016
				($ in millions)
Oil trades	Oil price volatility curves	17.32% - 25.95%	23.95%	$	(1	)
Natural gas trades	Natural gas price volatility curves	19.72% – 68.72%	30.71%	$	(9	)

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.

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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2014 Transactions

We sold certain assets in the southern Marcellus Shale and a portion of the eastern Utica Shale to a subsidiary of Southwestern Energy Company for aggregate net proceeds of approximately $4.975 billion. We sold approximately 413,000 net acres and approximately 1,500 wells in northern West Virginia and southern Pennsylvania, of which 435 wells are in the Marcellus or Utica formations, along with related gathering assets and property, plant and equipment.

We exchanged interests in approximately 440,000 gross acres in the Powder River Basin in southeastern Wyoming with RKI Exploration & Production, LLC (RKI). Under the agreement, we conveyed to RKI approximately 137,000 net acres and our interest in 67 gross wells with an average working interest of approximately 22% in the northern portion of the Powder River Basin, where RKI was the designated operator. In exchange, RKI conveyed to us approximately 203,000 net acres and its interest in 186 gross wells with an average working interest of 48% in the southern portion of the Powder River Basin, where we were the designated operator. In conjunction with the exchange, we paid RKI approximately $450 million in cash.

We sold noncore leasehold interests in the Marcellus Shale to Rice Drilling B LLC, a wholly owned subsidiary of Rice Energy Inc. (NYSE:RICE), for net proceeds of $233 million.

We sold noncore leasehold interests, producing properties and 61 wellhead compressor units in South Texas to Hilcorp Energy Company for net proceeds of $133 million. Operating obligations related to VPP #5 were also transferred. See Volumetric Production Payments below.

We sold noncore leasehold interests and producing properties in East Texas and Louisiana for net proceeds of approximately $63 million. All commitments related to VPP #6 were also transferred. See Volumetric Production Payments below.

Joint Ventures

In 2016, 2015 and 2014, 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 $7 million, $33 million and $33 million, respectively.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Volumetric Production Payments

From time to time, we have sold certain of our producing assets located in more mature producing regions through the sale of VPPs. 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. For all of our VPP transactions, we novated to each of the respective VPP buyers hedges that covered all VPP volumes sold. 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. Pursuant to SEC guidelines, the estimates used for purposes of determining the cost center ceiling and the standardized measure are based on current costs. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. The costs that will apply in the future 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.

For accounting purposes, cash proceeds from the sale of VPPs were reflected as a reduction of oil and natural gas properties with no gain or loss recognized, and our proved reserves were reduced accordingly. We have also committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.

As of December 31, 2016, 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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The volumes produced on behalf of our VPP buyers during 2016, 2015 and 2014 were as follows:



Year Ended December 31, 2016
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10(a)	108.0	3.0	368.7	5.9
9	152.4	12.9	347.1	15.9
4(a)	20.0	3.8	—	3.9
3(a)	—	2.4	—	2.4
2(a)	—	1.5	—	1.5
1(a)	—	11.1	—	11.1
	280.4	34.7	715.8	40.7

Year Ended December 31, 2015
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10(a)	310.0	8.5	1,043.9	16.6
9	167.9	14.2	375.9	17.4
8(b)	—	36.5	—	36.5
4(a)	42.5	8.0	—	8.2
3(a)	—	6.4	—	6.4
2(a)	—	4.0	—	4.0
1(a)	—	13.3	—	13.3
	520.4	90.9	1,419.8	102.4

Year Ended December 31, 2014
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10(a)	403.0	10.6	1,296.5	20.7
9	187.5	15.4	411.0	19.0
8(b)	—	60.1	—	60.1
6(c)	23.1	4.2	—	4.3
5(c)	16.5	4.6	—	4.7
4(a)	48.1	9.0	—	9.2
3(a)	—	7.2	—	7.2
2(a)	—	6.2	—	6.2
1(a)	—	13.8	—	13.8
	678.2	131.1	1,707.5	145.2


(a)	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.


(b)	VPP #8 expired in August 2015.


(c)	We divested the properties associated with VPP #5 and VPP #6 in 2014.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2016 were as follows:



		Volume Remaining as of December 31, 2016
VPP #	Term Remaining	Oil	Natural Gas	NGL	Total
	(in months)	(mmbbl)	(bcf)	(mmbbl)	(bcfe)
9	50	0.5	45.9	1.2	56.3

Spin-Off of Oilfield Services Business

On June 30, 2014, we completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary COO, into SSE, an independent, publicly traded company. Following the close of business on June 30, 2014, we distributed to Chesapeake shareholders one share of SSE common stock and cash in lieu of fractional shares for every 14 shares of Chesapeake common stock held on June 19, 2014, the record date for the distribution.

Prior to the completion of the spin-off, we and COO and its affiliates engaged in the following series of transactions:


•	COO and certain of its subsidiaries entered into a $275 million senior secured revolving credit facility and a $400 million secured term loan, the proceeds of which were used to repay in full and terminate COO’s then-existing credit facility.


•	COO distributed to us its compression unit manufacturing business, its geosteering business and the proceeds from the sale of substantially all of its crude oil hauling business.


•	We transferred to a subsidiary of COO, at carrying value, certain of our buildings and land, most of which COO had been leasing from us prior to the spin-off.


•	COO issued $500 million of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility and for general corporate purposes.

Following the spin-off, we have no ownership interest in SSE. Therefore, we ceased to consolidate SSE’s assets and liabilities as of the spin-off date. Because we expect to have significant continued involvement associated with SSE’s future operations through the various agreements we entered into in connection with the spin-off, our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations. For segment disclosures, we have labeled our oilfield services segment as “Former Oilfield Services”. See Note 21 for additional information regarding our segments.

In 2014, our stockholders’ equity decreased by $270 million, net of $151 million of associated deferred tax liabilities, as a result of the spin-off, and we recognized $15 million of charges associated with the spin-off that are included in restructuring and other termination costs on our consolidated statement of operations.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


14.	Investments

A summary of our investments, including our approximate ownership percentage and carrying value as of December 31, 2016 and 2015, is presented below.



		Approximate Ownership %		Carrying Value
	Accounting Method	December 31, 2016	December 31, 2015	December 31, 2016		December 31, 2015
				($ in millions)
Sundrop Fuels, Inc.	Equity	56%	56%	$	—	$	119
FTS International, Inc.	Equity	30%	30%	—		—
Other	—	—%	—%	7		17
Total investments(a)				$	7	$	136


(a)	Balance is included in other long-term assets on our consolidated balance sheets.

Sundrop Fuels, Inc. Sundrop Fuels, Inc. (Sundrop), based in Longmont, Colorado, is a privately held cellulosic biofuels company that is constructing a nonfood biomass-based “green gasoline” plant. Based on our review of the investment in Sundrop, we recognized an other-than-temporary impairment of $119 million in 2016. In 2015, we recorded a $20 million charge related to our share of Sundrop's net loss and $9 million of capitalized interest associated with the construction of Sundrop’s plant.

FTS International, Inc. FTS International, Inc. (FTS), based in Fort Worth, Texas, is a privately held company that, through its subsidiaries, provides hydraulic fracturing and other services to oil and gas companies. In 2015, we recorded our equity in FTS’ net losses and other adjustments, prior to intercompany profit eliminations, of $107 million and an accretion adjustment of $44 million related to the excess of our underlying equity in net assets of FTS over our carrying value. Due to the decrease in the oil and natural gas pricing environment, we recognized an other-than-temporary impairment on our investment in FTS of $53 million during 2015.

Sold Investments

Chaparral Energy, Inc. Chaparral Energy, Inc. (Chaparral), based in Oklahoma City, Oklahoma, is a private independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. In 2014, we sold all of our interest in Chaparral for net cash proceeds of $209 million. We recorded a $73 million gain related to the sale.

Other. In 2014, we sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


15.	Variable Interest Entities

We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.

Consolidated VIE

Chesapeake Granite Wash Trust (the Trust) is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust and because the royalty interest owners, other than Chesapeake, do not have the ability to exercise substantial liquidation rights. Our ownership in the Trust and our previous obligations under the development agreement constitute variable interests. We have determined that we are the primary beneficiary of the Trust because (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our operation of the majority of the producing wells and the completed development wells, and (ii) as a result of the subordination and incentive thresholds applicable to the subordinated units we hold in the Trust, we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to the Trust. As a result, we consolidate the Trust in our financial statements, and the common units of the Trust owned by third parties are reflected as a noncontrolling interest.

The Trust is a consolidated entity whose 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. In consolidation, as of December 31, 2016, $1 million of cash and cash equivalents, $488 million of proved oil and natural gas properties, $458 million of accumulated depreciation, depletion and amortization and $3 million of other current liabilities were attributable to the Trust. 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.

Unconsolidated VIE

Mineral Acquisition Company I, L.P. In 2012, MAC-LP, L.L.C., a wholly owned non-guarantor unrestricted subsidiary of Chesapeake, entered into a partnership agreement with KKR Royalty Aggregator LLC (KKR) to form Mineral Acquisition Company I, L.P. The purpose of the partnership was to acquire mineral interests, or royalty interests carved out of mineral interests, in oil and natural gas basins in the continental United States. The partnership was an unconsolidated VIE and the carrying value of our equity investment was $10 million as of December 31, 2015. During 2016, we sold certain mineral interests held outside the partnership for approximately $9 million, and assigned our interest in the partnership to KKR, which eliminated our future commitments to acquire additional mineral interests. As a result of the transaction, we wrote off our equity investment and recognized a $10 million loss which is included in net gain (loss) on sales of investments in our consolidated statements of operations.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


16.	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
	2016			2015
	($ in millions)						(in years)
Buildings and improvements	$	1,119		$	1,209		10 – 39
Computer equipment	337			318			5
Natural gas compressors(a)	251			483			3 – 20
Land	139			289
Gathering systems and treating plants(a)	2			214			20
Other	205			414			2 – 20
Total other property and equipment, at cost	2,053			2,927
Less: accumulated depreciation	(632		)	(813		)
Total other property and equipment, net	$	1,421		$	2,114


(a)	Included in our marketing, gathering and compression operating segment. The decrease is primarily related to asset divestitures in 2016.

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, 2016, 2015 and 2014 is as follows:



	Years Ended December 31,
	2016			2015		2014
	($ in millions)
Buildings and land	$	(1	)	$	3	$	(2	)
Natural gas compressors	(10		)	—		(195		)
Gathering systems and treating plants	—			1		8
Oilfield services equipment	—			—		(7		)
Other	(1		)	—		(3		)
Total net (gains) losses on sales of fixed assets	$	(12	)	$	4	$	(199	)

Natural Gas Compressors. In 2014, we sold 703 compressors to various parties for $693 million and recorded an aggregate gain of $195 million on the sales.

Assets Held for Sale

We are continuing to pursue the sale of buildings and land located primarily in Oklahoma and West Virginia. Buildings and land are recorded within our other segment. 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, 2016. 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, 2016 and 2015, we had $29 million and $95 million, respectively, of buildings and land, 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)


17.	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 2016 and 2015, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in impairments in the carrying value of our oil and natural gas properties of $2.564 billion and $18.238 billion, respectively. In 2014, we did not have an impairment for our oil and natural gas properties. Cash flow hedges which relate to future periods increased the ceiling test impairment by $176 million in 2015.

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, 2016, 2015 and 2014 is as follows:



	Years Ended December 31,
	2016		2015		2014
	($ in millions)
Barnett Shale exit costs	$	645	$	—	$	—
Devonian Shale exit costs	142		—		—
Gathering systems	3		—		13
Natural gas compressors	21		21		11
Buildings and land	11		—		18
Oilfield services equipment	—		—		23
Other	16		173		23
Total impairments of fixed assets and other	$	838	$	194	$	88

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.

Oilfield Services Equipment. In 2014, we purchased 31 leased rigs and equipment from various lessors for an aggregate purchase price of $140 million. In connection with these purchases, we paid $8 million in early lease termination costs, which are included in impairments of fixed assets and other in the consolidated statement of operations. In addition, we recognized an impairment loss of approximately $15 million related to leasehold improvements associated with these assets. The drilling rigs and equipment are included in our former oilfield services operating segment.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Other. 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 (see Note 12), 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. The contract termination charges are included in our exploration and production operating segment. In 2014, we revised our estimate of our net acreage shortfall with Total under the terms of our Barnett Shale joint venture agreement and recorded a $22 million charge. See Note 4 for additional discussion regarding our net acreage maintenance commitments.

Nonrecurring Fair Value Measurements. Fair value measurements for certain of the impairments discussed above 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.


18.	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.

Oilfield Services Spin-Off

On June 30, 2014, we completed the spin-off of our oilfield services business through a pro rata distribution of SSE common stock to holders of Chesapeake common stock. In connection with the spin-off, in 2014, we incurred restructuring charges of $15 million, including transaction costs of $17 million, stock-based compensation adjustments of $5 million for Chesapeake employees, credits of $10 million of forfeitures for Seventy Seven Energy employees and $3 million in debt extinguishment costs. See Note 13 for further discussion of the spin-off.

Other

We recognized credits of $19 million and $8 million in 2015 and 2014, respectively, 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)


19.	Fair Value Measurements

Recurring Fair Value Measurements

Other Current Assets. Assets related to Chesapeake’s 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 Chesapeake’s 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, 2016 and 2015:



	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, 2016
Financial Assets (Liabilities):
Other current assets	$	49		$	—	$	—	$	49
Other current liabilities	(51		)	—		—		(51		)
Total	$	(2	)	$	—	$	—	$	(2	)

As of December 31, 2015
Financial Assets (Liabilities):
Other current assets	$	50		$	—	$	—	$	50
Other current liabilities	(51		)	—		—		(51		)
Total	$	(1	)	$	—	$	—	$	(1	)

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 17 regarding nonrecurring fair value measurements.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


20.	Asset Retirement Obligations

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



	Years Ended December 31,
	2016			2015
	($ in millions)
Asset retirement obligations, beginning of period	$	473		$	465
Additions	4			6
Revisions(a)	(58		)	13
Settlements and disposals(b)	(182		)	(34		)
Accretion expense	24			23
Asset retirement obligations, end of period	261			473
Less current portion (c)	14			21
Asset retirement obligation, long-term	$	247		$	452


(a)	Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and the expected timing of settlement.


(b)	Settlements and disposals in 2016 relate primarily to wells divested in the Barnett and Devonian Shale areas.


(c)	Balance is included in other current liabilities on our consolidated balance sheets.


21.	Major Customers and Segment Information

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. Sales to Exxon Mobil Corporation constituted approximately 12% of our total revenues (before the effects of hedging) for the year ended December 31, 2014.

As of December 31, 2016, we have two reportable operating segments, each of which is managed separately because of the nature of its operations. The exploration and production operating segment is responsible for finding and producing oil, natural gas and NGL. The marketing, gathering and compression operating segment is responsible for marketing, gathering and compression of oil, natural gas and NGL. In addition, prior to the spin-off of our oilfield services business in June 2014, our former oilfield services operating segment was responsible for drilling, oilfield trucking, oilfield rentals, hydraulic fracturing and other oilfield services for both Chesapeake-operated wells and wells operated by third parties. Our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations, as reflected in the table below.

Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the sale of oil, natural gas and NGL related to Chesapeake’s ownership interests by our marketing, gathering and compression operating segment are reflected as revenues within our exploration and production operating segment. These amounts totaled $3.750 billion, $4.372 billion and $8.565 billion for the years ended December 31, 2016, 2015 and 2014, respectively. Revenues generated by our former oilfield services operating segment for work performed for Chesapeake’s exploration and production operating segment were reclassified to the full cost pool based on Chesapeake’s ownership interest. Revenues reclassified totaled $544 million for year ended December 31, 2014. No income was recognized in our consolidated statements of operations related to oilfield services performed for Chesapeake-operated wells.

During the 2016 first quarter, we changed the structure of our internal organization to include certain assets in our Exploration and Production reportable segment instead of our Other segment. Accordingly, this change has been reflected through retroactive revision of the segment information as of December 31, 2015 and 2014, as shown in the tables below.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents selected financial information for Chesapeake’s operating segments:



	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services		Other			Intercompany Eliminations			Consolidated Total
	($ in millions)
Year Ended December 31, 2016
Revenues	$	3,288		$	8,334		$	—	$	—		$	(3,750	)	$	7,872
Intersegment revenues	—			(3,750		)	—		—			3,750			—
Total revenues	$	3,288		$	4,584		$	—	$	—		$	—		$	7,872

Unrealized losses on commodity derivatives	$	819		$	—		$	—	$	—		$	—		$	819
Unrealized losses on marketing derivatives	$	—		$	297		$	—	$	—		$	—		$	297
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	1,024		$	45		$	—	$	38		$	—		$	1,107
Impairment of oil and natural gas properties	$	2,564		$	—		$	—	$	—		$	—		$	2,564
Impairments of fixed assets and other	$	387		$	220		$	—	$	231		$	—		$	838
Net gain (loss) on sales of fixed assets	$	(4	)	$	(7	)	$	—	$	(1	)	$	—		$	(12	)
Interest expense	$	(303	)	$	—		$	—	$	7		$	—		$	(296	)
Losses on investments	$	—		$	—		$	—	$	(8	)	$	—		$	(8	)
Impairments of investments	$	—		$	—		$	—	$	(119	)	$	—		$	(119	)
Gains on purchases or exchanges of debt	$	236		$	—		$	—	$	—		$	—		$	236

Income (Loss) Before Income Taxes	$	(4,099	)	$	(112	)	$	—	$	(378	)	$	—		$	(4,589	)
Total Assets	$	11,249		$	1,118		$	—	$	1,059		$	(398	)	$	13,028
Capital Expenditures	$	1,439		$	7		$	—	$	—		$	—		$	1,446

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services		Other			Intercompany Eliminations			Consolidated Total
	($ in millions)
Year Ended December 31, 2015
Revenues	$	5,391		$	11,745		$	—	$	—		$	(4,372	)	$	12,764
Intersegment revenues	—			(4,372		)	—		—			4,372			—
Total revenues	$	5,391		$	7,373		$	—	$	—		$	—		$	12,764

Unrealized losses on commodity derivatives	$	693		$	—		$	—	$	—		$	—		$	693
Unrealized gains on marketing derivatives	$	—		$	(295	)	$	—	$	—		$	—		$	(295	)
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,170		$	20		$	—	$	39		$	—		$	2,229
Impairment of oil and natural gas properties	$	18,238		$	—		$	—	$	—		$	—		$	18,238
Impairments of fixed assets and other	$	126		$	68		$	—	$	—		$	—		$	194
Net gain (loss) on sales of fixed assets	$	1		$	1		$	—	$	2		$	—		$	4
Interest expense	$	(925	)	$	(4	)	$	—	$	6		$	606		$	(317	)
Losses on investments	$	(3	)	$	—		$	—	$	(93	)	$	—		$	(96	)
Impairments of investments	$	—		$	—		$	—	$	(53	)	$	—		$	(53	)
Gains on purchases or exchanges of debt	$	279		$	—		$	—	$	—		$	—		$	279
							—
Income (Loss) Before Income Taxes	$	(19,619	)	$	117		$	—	$	(127	)	$	531		$	(19,098	)
Total Assets (as previously reported)	$	11,776		$	1,524		$	—	$	4,325		$	(311	)	$	17,314
Total Assets (as revised)	$	14,610		$	1,524		$	—	$	1,491		$	(311	)	$	17,314
Capital Expenditures	$	3,562		$	42		$	—	$	10		$	—		$	3,614

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services			Other			Intercompany Eliminations			Consolidated Total
	($ in millions)
Year Ended December 31, 2014
Revenues	$	10,354		$	20,790		$	1,060		$	30		$	(9,109	)	$	23,125
Intersegment revenues	—			(8,565		)	(544		)	—			9,109			—
Total revenues	$	10,354		$	12,225		$	516		$	30		$	—		$	23,125

Unrealized losses on commodity derivatives	$	(1,394	)	$	—		$	—		$	—		$	—		$	(1,394	)
Unrealized gains on marketing derivatives	$	—		$	(3	)	$	—		$	—		$	—		$	(3	)
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,756		$	38		$	145		$	42		$	(66	)	$	2,915
Impairments of fixed assets and other	$	22		$	24		$	23		$	19		$	—		$	88
Net gain (loss) on sales of fixed assets	$	(2	)	$	(187	)	$	(8	)	$	(2	)	$	—		$	(199	)
Interest expense	$	(709	)	$	(21	)	$	(42	)	$	3		$	680		$	(89	)
Losses on investments	$	2		$	—		$	(1	)	$	(76	)	$	—		$	(75	)
Impairments of investments	$	—		$	—		$	(5	)	$	—		$	—		$	(5	)
Net loss on sales of investments	$	(6	)	$	—		$	—		$	73		$	—		$	67
Gains on purchases or exchanges of debt	$	(197	)	$	—		$	—		$	—		$	—		$	(197	)

Income (Loss) Before Income Taxes	$	2,874		$	326		$	(16	)	$	(30	)	$	46		$	3,200
Total Assets (as previously reported)	$	35,285		$	1,978		$	—		$	4,283		$	(891	)	$	40,655
Total Assets (as revised)	$	38,012		$	1,978		$	—		$	1,556		$	(891	)	$	40,655
Capital Expenditures	$	6,173		$	298		$	158		$	38		$	—		$	6,667

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


22.	Recently Issued Accounting Standards

In May 2014, the FASB issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the company expects to receive in the exchange. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early application not permitted. In July 2015, the FASB approved a one-year deferral of the effective date as well as permission to early adopt the new revenue recognition standard as of the original effective date. In March 2016, the FASB issued an update clarifying the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued an update clarifying the identification of performance obligations and licensing implementations guidance. In May 2016, the FASB issued an update clarifying guidance in a few narrow areas and added some practical expedients to the guidance. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures.

In August 2014, the FASB issued updated guidance that requires management, for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the consolidated financial statements are issued. If management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern, certain disclosures are required to be made within the footnotes to the consolidated financial statements. The amendments in this update are effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. We adopted this guidance as of December 31, 2016, and it had no impact on our consolidated financial statements and related disclosures.

In February 2016, the FASB issued updated lease accounting guidance requiring companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures.

In March 2016, the FASB issued guidance for improvements to employee share-based payment accounting to simplify the accounting for share-based compensation. The new standard requires all excess tax benefits and reductions from differences between the deduction for tax purposes and the compensation cost recorded for financial reporting purposes be recognized as income tax expense or benefit in the income statement and not recognized as additional paid-in capital. The new standard also requires all excess tax benefits and deficiencies to be classified as operating activity within the statement of cash flows. For public business entities, the amendments are effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted in any interim or annual period, with any adjustments reflected as of the beginning of the fiscal year of adoption. We have elected to early adopt the amendments effective January 1, 2016. The cumulative-effect adjustment to retained earnings for all excess tax benefits not previously recognized as of the beginning period is fully offset by a corresponding change in the valuation allowance resulting in no change to our consolidated financial statements. The implementation of this guidance did not have a material impact on our consolidated financial statements and related disclosures.

In March 2016, the FASB issued new guidance that will result in fewer put or call options embedded in debt instruments qualifying for separate derivative accounting because companies will not be required to assess whether the contingent event, such as change in control or an IPO, is related to interest rates or credit risks. This standard is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


23.	Subsequent Events

In January 2017, we purchased and retired approximately $287 million principal amount of our outstanding contingent convertible senior notes and $2 million principal amount of our outstanding senior notes for an aggregate of $286 million pursuant to tender offers.

In January 2017, we completed private exchanges of an aggregate of approximately 10.0 million shares of our common stock for (i) 150,948 shares of 5.00% Cumulative Convertible Preferred Stock (Series 2005B), (ii) 72,600 shares of 5.75% Cumulative Convertible Preferred Stock and (iii) 12,500 shares of 5.75% Cumulative Convertible Preferred Stock (Series A).

In January 2017, we sold a portion of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $450 million, subject to certain customary post-closing adjustments. Included in the sale were approximately 78,000 net acres. The sale also included 250 wells currently producing approximately 30 mmcf of gas per day.

In January 2017, we redeemed our $133 million principal amount of outstanding 6.5% Senior Notes due 2017.

In January 2017, we repurchased in the open market approximately $221 million principal amount of our outstanding debt scheduled to mature or that could be put to us in 2018 and 2020 for $224 million.

In February 2017, we reinstated the payment of dividends on each series of our outstanding convertible preferred stock and paid our dividends in arrears.

In February 2017, we sold a portion of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $465 million, subject to certain customary post-closing adjustments. Included in the sale were approximately 41,500 net acres. The sale also included 326 operated and non-operated wells currently producing approximately 50 mmcf of gas per day.

In February 2017, we paid $290 million to assign an oil transportation agreement. This assignment is expected to reduce our future oil transportation commitments by approximately $450 million. The assignment is effective April 1, 2017. In addition, we terminated future natural gas transportation commitments related to divested assets of approximately $110 million for a cash payment of approximately $100 million. This termination was effective March 1, 2017.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

Quarterly Financial Data (unaudited)

Summarized unaudited quarterly financial data for 2016 and 2015 are as follows:



2016 First Quarter	As Previously Reported			Adjustment(b)			As Revised
	($ in millions except per share data)
Total revenues	$	1,953		$	—		$	1,953
Gross profit(a)	$	(952	)	$	(147	)	$	(1,099	)
Net loss attributable to Chesapeake	$	(921	)	$	(147	)	$	(1,068	)
Net loss available to common stockholders	$	(964	)	$	(147	)	$	(1,111	)

Net loss per common share:
Basic	$	(1.44	)	$	(0.21	)	$	(1.65	)
Diluted	$	(1.44	)	$	(0.21	)	$	(1.65	)



2016 Second Quarter	As Previously Reported			Adjustment(b)			As Revised
	($ in millions except per share data)
Total revenues	$	1,622		$	—		$	1,622
Gross profit(a)	$	(1,757	)	$	(26	)	$	(1,783	)
Net loss attributable to Chesapeake	$	(1,750	)	$	(26	)	$	(1,776	)
Net loss available to common stockholders	$	(1,792	)	$	(26	)	$	(1,818	)

Net loss per common share:
Basic	$	(2.48	)	$	(0.05	)	$	(2.53	)
Diluted	$	(2.48	)	$	(0.05	)	$	(2.53	)



2016 Third Quarter	As Previously Reported			Adjustment(b)			As Revised
	($ in millions except per share data)
Total revenues	$	2,276		$	—		$	2,276
Gross profit(a)	$	(1,174	)	$	(60	)	$	(1,234	)
Net loss attributable to Chesapeake	$	(1,155	)	$	(60	)	$	(1,215	)
Net loss available to common stockholders	$	(1,197	)	$	(60	)	$	(1,257	)

Net loss per common share:
Basic	$	(1.54	)	$	(0.08	)	$	(1.62	)
Diluted	$	(1.54	)	$	(0.08	)	$	(1.62	)



2016 Fourth Quarter
	($ in millions)
Total revenues	$	2,021
Gross profit(a)	$	(295	)
Net loss attributable to Chesapeake	$	(342	)
Net loss available to common stockholders	$	(740	)

Net loss per common share:	($ per share)
Basic	$	(0.83	)
Diluted	$	(0.83	)



	2015 First Quarter			2015 Second Quarter			2015 Third Quarter			2015 Fourth Quarter
	($ in millions except per share data)
Total revenues	$	3,218		$	3,521		$	3,376		$	2,649
Gross profit(a)	$	(5,040	)	$	(5,507	)	$	(5,453	)	$	(2,919	)
Net loss attributable to Chesapeake	$	(3,739	)	$	(4,108	)	$	(4,653	)	$	(2,185	)
Net loss available to common stockholders	$	(3,782	)	$	(4,151	)	$	(4,695	)	$	(2,228	)

Net loss per common share:
Basic	$	(5.72	)	$	(6.27	)	$	(7.08	)	$	(3.36	)
Diluted	$	(5.72	)	$	(6.27	)	$	(7.08	)	$	(3.36	)


(a)	Total revenue less operating expenses. Includes $2.564 billion and $18.238 billion in ceiling test write-downs on our oil and natural gas properties for the years ended December 31, 2016 and 2015, respectively.

(b)

During our review of the full cost ceiling test calculation for the fourth quarter of 2016, we identified certain errors to the basis price differentials used in calculating the impairment of oil and natural gas properties and oil, natural gas and NGL depreciation, depletion and amortization for each of the first three interim periods in 2016. We determined that these errors do not relate to periods prior to January 1, 2016.

The impact of the errors was an understatement in the impairment of oil and natural gas properties of $144 million for the quarter ended March 31, 2016, $24 million for the quarter ended June 30, 2016 and $64 million for the quarter ended September 30, 2016. The impact of the error was also an overstatement in the oil, natural gas and NGL depreciation, depletion and amortization of $8 million for the quarter ended March 31, 2016, an understatement of $13 million for the quarter ended June 30, 2016 and an overstatement of $4 million for the quarter ended September 30, 2016. In accordance with Staff Accounting Bulletin No. 99, Materiality, management evaluated the materiality of the errors from qualitative and quantitative perspectives and concluded that the errors are not material to our previously issued interim financial statements. Accordingly, the corrections for these errors and an other immaterial previously identified error is reflected in the table above. The corrections associated with these errors will also be reflected in our 2017 Form 10-Q filings.

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 Chesapeake's oil, natural gas and NGL producing activities are summarized as follows:



	December 31,
	2016			2015
	($ in millions)
Oil and oil and natural gas properties:
Proved	$	66,451		$	63,843
Unproved	4,802			6,798
Total	71,253			70,641
Less accumulated depreciation, depletion and amortization	(62,094		)	(58,552		)
Net capitalized costs	$	9,159		$	12,089

Unproved properties not subject to amortization as of December 31, 2016 and 2015, consisted mainly of leasehold acquired through direct purchases of significant oil and natural gas property interests. We capitalized approximately $242 million, $410 million and $604 million of interest during 2016, 2015 and 2014, 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,
	2016		2015		2014
	($ in millions)
Acquisition of Properties:
Proved properties	$	403	$	—	$	214
Unproved properties	403		454		1,224
Exploratory costs	52		112		421
Development costs	1,312		2,941		4,204
Costs incurred(a)(b)	$	2,170	$	3,507	$	6,063


(a)	Exploratory and development costs are net of $51 million and $679 million in drilling and completion carries received from our joint venture partners during 2015 and 2014, respectively.


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



Capitalized interest	$	242		$	410		$	604
Asset retirement obligations	$	(57	)	$	(15	)	$	39

In 2016, we invested approximately $312 million, to convert 118 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

Chesapeake's results of operations from oil, natural gas and NGL producing activities are presented below for 2016, 2015 and 2014. 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,
	2016			2015			2014
	($ in millions)
Oil, natural gas and NGL sales	$	3,288		$	5,391		$	10,354
Oil, natural gas and NGL production expenses	(710		)	(1,046		)	(1,208		)
Oil, natural gas and NGL gathering, processing and transportation expenses	(1,855		)	(2,119		)	(2,174		)
Production taxes	(74		)	(99		)	(232		)
Impairment of oil and natural gas properties	(2,564		)	(18,238		)	—
Depletion and depreciation	(1,003		)	(2,099		)	(2,683		)
Imputed income tax provision(a)	1,027			6,683			(1,485		)
Results of operations from oil, natural gas and NGL producing activities	$	(1,891	)	$	(11,527	)	$	2,572


(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

Chesapeake's petroleum engineers and independent petroleum engineering firms estimated all of our proved reserves as of December 31, 2016, 2015 and 2014. Independent petroleum engineering firms estimated an aggregate of 70%, 59% and 79% of our estimated proved reserves (by volume) as of December 31, 2016, 2015 and 2014, respectively, as set forth below.



	December 31,
	2016	2015		2014
Ryder Scott Company, L.P.	—%	36	%	54	%
Software Integrated Solutions, Division of Schlumberger Technology Corporation	70%	23	%	25	%

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 2016, 2015 and 2014.



	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(a)	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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION – (Continued)



	Oil		Gas		NGL		Total
	(mmbbl)		(bcf)		(mmbbl)		(mmboe)
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(c)	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

December 31, 2014
Proved reserves, beginning of period	423.8		11,734		299.0		2,678
Extensions, discoveries and other additions	108.6		1,567		78.2		448
Revisions of previous estimates	(51.1	)	(129	)	21.3		(51	)
Production	(42.3	)	(1,095	)	(33.1	)	(258	)
Sale of reserves-in-place	(23.3	)	(1,421	)	(101.7	)	(362	)
Purchase of reserves-in-place	5.1		36		2.6		14
Proved reserves, end of period(d)	420.8		10,692		266.3		2,469
Proved developed reserves:
Beginning of period	201.3		8,584		177.1		1,809
End of period	229.3		8,615		198.5		1,864
Proved undeveloped reserves:
Beginning of period	222.5		3,150		121.9		869
End of period(b)	191.5		2,077		67.8		605


(a)	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.


(b)	As of December 31, 2016, 2015 and 2014, there were no PUDs that had remained undeveloped for five years or more.


(c)	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.


(d)	Includes 2 mmbbls of oil, 46 bcf of natural gas and 5 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbl of oil, 22 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 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 the 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.

During 2014, we acquired approximately 14 mmboe of proved reserves through purchases of oil and natural gas properties for consideration of $168 million, and we sold 362 mmboe of proved reserves for approximately $4.7 billion. We recorded downward revisions of 51 mmboe, including a 78 mmboe reduction in previous estimates partially offset by a 27 mmboe increase, primarily the result of higher natural gas prices in 2014. The oil and natural gas prices used in computing our reserves as of December 31, 2014, were $94.98 per bbl and $4.35 per mcf, respectively, before price differentials. Including the effect of price differential adjustments, the prices used in computing our reserves as of December 31, 2014 were $89.09 per barrel of oil, $2.68 per mcf of natural gas and $24.10 per barrel of NGL.

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, 2016, 2015 and 2014 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,
	2016				2015				2014
	($ in millions)
Future cash inflows	$	19,835		(a)	$	20,247		(b)	$	72,557		(c)
Future production costs	(6,800		)		(7,391		)		(17,036		)
Future development costs	(3,621		)		(1,518		)		(7,556		)
Future income tax provisions	(79		)		(228		)		(12,494		)
Future net cash flows	9,335				11,110				35,471
Less effect of a 10% discount factor	(4,956		)		(6,417		)		(18,338		)
Standardized measure of discounted future net cash flows(d)	$	4,379			$	4,693			$	17,133


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


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


(c)	Calculated using prices of $94.98 per bbl of oil and $4.35 per mcf of natural gas, before field differentials.


(d)	Excludes future cash inflows attributable to production volumes sold to VPP buyers and includes future cash outflows attributable to the costs of production. 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,
	2016			2015			2014
	($ in millions)
Standardized measure, beginning of period(a)	$	4,693		$	17,133		$	17,390
Sales of oil and natural gas produced, net of production costs and gathering, processing and transportation(b)	(1,227		)	(1,503		)	(5,722		)
Net changes in prices and production costs	(1,210		)	(18,070		)	(634		)
Extensions and discoveries, net of production and development costs	1,042			1,005			5,156
Changes in estimated future development costs	323			3,198			1,946
Previously estimated development costs incurred during the period	664			873			1,178
Revisions of previous quantity estimates	145			(3,472		)	(715		)
Purchase of reserves-in-place	394			1			215
Sales of reserves-in-place	13			(938		)	(1,788		)
Accretion of discount	473			2,201			2,168
Net change in income taxes	(8		)	4,845			(593		)
Changes in production rates and other	(923		)	(580		)	(1,468		)
Standardized measure, end of period(a)(c)(d)	$	4,379		$	4,693		$	17,133


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


(b)	Excluding gains (losses) on derivatives.


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


(d)	The standardized measure of discounted future net cash flows does not include estimated future cash inflows attributable to future production of VPP volumes sold and does include estimated future cash outflows attributable to the costs of future production of VPP volumes sold.

Previous: Item 7A. Quantitative and Qualitative Disclosures About Market Risk · Next: Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure