Item 8. Financial Statements and Supplementary Data

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Item 8. Financial Statements and Supplementary Data


	INDEX TO FINANCIAL STATEMENTS CHESAPEAKE ENERGY CORPORATION (DEBTOR-IN-POSSESSION)
		Page
Report of Independent Registered Public Accounting Firm		66
Consolidated Financial Statements:
	Consolidated Balance Sheets as of December 31, 2020 and 2019	69
	Consolidated Statements of Operations for the Years Ended December 31, 2020, 2019 and 2018	71
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2020, 2019 and 2018	72
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018	73
	Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2020, 2019 and 2018	75
Notes to the Consolidated Financial Statements:
	Note 1. Basis of Presentation and Summary of Significant Accounting Policies	77
	Note 2. Chapter 11 Proceedings	82
	Note 3. Oil and Natural Gas Property Transactions	87
	Note 4. Earnings per Share	91
	Note 5. Debt	92
	Note 6. Contingencies and Commitments	99
	Note 7. Other Liabilities	101
	Note 8. Leases	102
	Note 9. Revenue Recognition	104
	Note 10. Income Taxes	106
	Note 11. Equity	110
	Note 12. Share-Based Compensation	113
	Note 13. Employee Benefit Plans	117
	Note 14. Derivative and Hedging Activities	118
	Note 15. Capitalized Exploratory Well Costs	123
	Note 16. Other Property and Equipment	124
	Note 17. Investments	124
	Note 18. Impairments	125
	Note 19. Exploration Expense	126
	Note 20. Other Operating Expense	126
	Note 21. Separation and Other Termination Costs	127
	Note 22. Asset Retirement Obligations	127
	Note 23. Major Customers	127
	Note 24. Condensed Combined Debtor-in-Possession Financial Information	128
	Note 2 5 . Subsequent Events	131

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Supplementary Information:
	Quarterly Financial Data (unaudited)	132
	Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited)	133

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Chesapeake Energy Corporation

Opinions on the Financial Statements

We have audited the accompanying consolidated balance sheets of Chesapeake Energy Corporation and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of operations, of comprehensive income (loss), of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Subsequent Event

As discussed in Note 2 to the consolidated financial statements, Chesapeake Energy Corporation and certain of its subsidiaries (collectively the “Debtors”) filed voluntary petitions on June 28, 2020 with the United States Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”) for relief under the provisions of Chapter 11 of the United States Code Bankruptcy Code. The Bankruptcy Court confirmed the Debtors joint plan of reorganization on January 16, 2021 and the Debtors emerged from Bankruptcy on February 9, 2021.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

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The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Natural Gas Properties, Net

As described in Note 1 to the consolidated financial statements, the Company’s property and equipment, net balance was $5.2 billion as of December 31, 2020, and depreciation, depletion, and amortization (DD&A) expense for the year ended December 31, 2020 was $1.1 billion, both of which substantially related to proved oil and natural gas properties. The Company follows the successful efforts method of accounting for its oil and natural gas producing activities. Under this method, all capitalized well costs and leasehold costs of proved oil and natural gas properties are depreciated by the units-of-production (UOP) method based on total estimated proved developed reserves and proved reserves, respectively. As disclosed by management, estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of management’s 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 volumes may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. The estimates of oil and natural gas reserves have been developed by specialists, specifically petroleum engineers.

The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on proved oil and natural gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserves volumes and the assumptions applied to the data related to the commodity pricing differentials and future development costs.

Impairment Assessment of Certain Proved Oil and Natural Gas Properties

As described in Notes 1 and 18 to the consolidated financial statements, the property and equipment, net balance was $5.2 billion as of December 31, 2020, and impairment expense for the year ended December 31, 2020 was $8.5 billion, both of which substantially related to proved oil and natural gas properties. When circumstances indicate that the carrying value of proved oil and natural gas properties may not be recoverable, management compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using an income approach. The expected future cash flows used for impairment assessment and related fair value measurements are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, weighted average cost of capital and capital investment plans, considering all available information at the date of assessment.

The principal considerations for our determination that performing procedures relating to the impairment assessment of certain proved oil and natural gas properties is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the fair value measurement of proved oil and natural gas properties; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future production volumes, commodity prices, and operating costs, as well as the weighted average cost of capital; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

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Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of certain controls relating to management’s proved oil and natural gas properties impairment assessment. These procedures also included, among others (i) testing management’s process for developing the fair value measurement of proved oil and natural gas properties; (ii) evaluating the appropriateness of the income approach model; (iii) testing the completeness and accuracy of underlying data used in the model; and (iv) evaluating the reasonableness of significant assumptions used by management related to future production volumes, commodity prices, and operating costs, as well as the weighted average cost of capital. Evaluating the reasonableness of management’s assumptions related to future commodity prices involved comparing the prices against observable market data and evaluating differentials through inspection of the underlying contracts. Evaluating future operating costs involved evaluating the reasonableness of the assumptions as compared to the past performance of the Company. Professionals with specialized skill and knowledge were used to assist in the evaluation of the Company’s income approach model and weighted average cost of capital. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes as stated in the Critical Audit Matter titled “The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Natural Gas Properties, Net” and the reasonableness of the future production volumes. As a basis for using this work, the specialists’ qualifications were understood and, the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

March 1, 2021

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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONSOLIDATED BALANCE SHEETS


	December 31,
	2020		2019
ASSETS	($ in millions)
CURRENT ASSETS:
Cash and cash equivalents ($0 and $2 attributable to our VIE)	$	279	$	6
Accounts receivable, net	746		990
Short-term derivative assets	19		134
Other current assets	64		121
Total Current Assets	1,108		1,251
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on successful efforts accounting:
Proved oil and natural gas properties ($0 and $755 attributable to our VIE)	25,734		30,765
Unproved properties	1,550		2,173
Other property and equipment	1,754		1,810
Total Property and Equipment, at Cost	29,038		34,748
Less: accumulated depreciation, depletion and amortization ($0 and ($713) attributable to our VIE)	(23,806)		(20,002)
Property and equipment held for sale, net	10		10
Total Property and Equipment, Net	5,242		14,756
Other long-term assets	234		186
TOTAL ASSETS	$	6,584	$	16,193

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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONSOLIDATED BALANCE SHEETS – (Continued)


	December 31,
	2020		2019
LIABILITIES AND EQUITY (DEFICIT)	($ in millions)
CURRENT LIABILITIES:
Accounts payable	$	346	$	498
Current maturities of long-term debt, net	1,929		385
Accrued interest	3		75
Short-term derivative liabilities	93		2
Other current liabilities ($0 and $1 attributable to our VIE)	723		1,432
Total Current Liabilities	3,094		2,392
Long-term debt, net	—		9,073
Long-term derivative liabilities	44		2
Asset retirement obligations, net of current portion	139		200
Other long-term liabilities	5		125
Liabilities subject to compromise	8,643		—
Total Liabilities	11,925		11,792
CONTINGENCIES AND COMMITMENTS (Note 6)
EQUITY (DEFICIT):
Stockholders’ Equity (deficit):
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 5,563,458 and 5,563,458 shares outstanding	1,631		1,631
Common stock, $0.01 par value, 22,500,000 and 15,000,000 shares authorized: 9,780,547 and 9,772,793 shares issued(a)	—		—
Additional paid-in capital	16,937		16,973
Accumulated deficit	(23,954)		(14,220)
Accumulated other comprehensive income	45		12
Less: treasury stock, at cost; 0 and 26,224 common shares(a)	—		(32)
Total Stockholders’ Equity (Deficit)	(5,341)		4,364
Noncontrolling interests	—		37
Total Equity (Deficit)	(5,341)		4,401
TOTAL LIABILITIES AND EQUITY (DEFICIT)	$	6,584	$	16,193

(a) Amounts and shares have been retroactively adjusted to reflect a 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information.

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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES - (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2020		2019		2018
	($ in millions except per share data)
REVENUES AND OTHER:
Oil, natural gas and NGL	$	3,341	$	4,522	$	5,155
Marketing	1,869		3,967		5,076
Total Revenues	5,210		8,489		10,231
Other	56		63		63
Gains (losses) on sales of assets	30		43		(264)
Total Revenues and Other	5,296		8,595		10,030
OPERATING EXPENSES:
Oil, natural gas and NGL production	373		520		474
Oil, natural gas and NGL gathering, processing and transportation	1,082		1,082		1,398
Severance and ad valorem taxes	149		224		189
Exploration	427		84		162
Marketing	1,889		4,003		5,158
General and administrative	267		315		335
Separation and other termination costs	44		12		38
Provision for legal contingencies	27		19		26
Depreciation, depletion and amortization	1,097		2,264		1,737
Impairments	8,535		11		131
Other operating expense	109		92		—
Total Operating Expenses	13,999		8,626		9,648
INCOME (LOSS) FROM OPERATIONS	(8,703)		(31)		382
OTHER INCOME (EXPENSE):
Interest expense	(331)		(651)		(633)
Gains (losses) on investments	(20)		(71)		139
Gains on purchases or exchanges of debt	65		75		263
Other income	16		39		67
Reorganization items, net	(796)		—		—
Total Other Expense	(1,066)		(608)		(164)
INCOME (LOSS) BEFORE INCOME TAXES	(9,769)		(639)		218
INCOME TAX EXPENSE (BENEFIT):
Current income taxes	(9)		(26)		—
Deferred income taxes	(10)		(305)		(10)
Total Income Tax Expense (Benefit)	(19)		(331)		(10)
NET INCOME (LOSS)	(9,750)		(308)		228
Net (income) loss attributable to noncontrolling interests	16		—		(2)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(9,734)		(308)		226
Preferred stock dividends	(22)		(91)		(92)
Loss on exchange of preferred stock	—		(17)		—
Earnings allocated to participating securities	—		—		(1)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	(9,756)	$	(416)	$	133
EARNINGS (LOSS) PER COMMON SHARE:(a)
Basic	$	(998.26)	$	(49.97)	$	29.26
Diluted	$	(998.26)	$	(49.97)	$	29.26
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in thousands):(a)
Basic	9,773		8,325		4,546
Diluted	9,773		8,325		4,546

(a) All share and per share information has been retroactively adjusted to reflect a 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information.

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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
NET INCOME (LOSS)	$	(9,750)	$	(308)	$	228
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Reclassification of losses on settled derivative instruments(a)	33		35		34
Other Comprehensive Income	33		35		34
COMPREHENSIVE INCOME (LOSS)	(9,717)		(273)		262
COMPREHENSIVE (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	16		—		(2)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	(9,701)	$	(273)	$	260

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

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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$	(9,750)	$	(308)	$	228
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	1,097		2,264		1,737
Deferred income tax benefit	(10)		(305)		(10)
Derivative (gains) losses, net	(596)		(3)		26
Cash receipts (payments) on derivative settlements, net	884		202		(345)
Stock-based compensation	21		30		32
(Gains) losses on sales of assets	(30)		(43)		264
Impairments	8,535		11		131
Non-cash reorganization items, net	(213)		—		—
Exploration	417		49		96
(Gains) losses on investments	20		63		(139)
Gains on purchases or exchanges of debt	(65)		(79)		(263)
Other	(61)		(4)		(118)
Decrease in accounts receivable and other assets	303		376		16
(Decrease) increase in accounts payable, accrued liabilities and other	612		(630)		75
Net Cash Provided By Operating Activities	1,164		1,623		1,730
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(1,111)		(2,180)		(1,848)
Business combination, net	—		(353)		—
Acquisitions of proved and unproved properties	(9)		(35)		(128)
Proceeds from divestitures of proved and unproved properties	136		130		2,231
Additions to other property and equipment	(22)		(48)		(21)
Proceeds from sales of other property and equipment	14		6		147
Proceeds from sales of investments	—		—		74
Net Cash Provided By (Used In) Investing Activities	(992)		(2,480)		455

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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from pre-petition revolving credit facility borrowings	3,656		10,676		11,697
Payments on pre-petition revolving credit facility borrowings	(3,317)		(10,180)		(12,059)
Proceeds from DIP credit facility borrowings	60		—		—
Payments on DIP credit facility borrowings	(60)		—		—
DIP credit facility and exit facilities financing costs	(109)		—		—
Proceeds from issuance of senior notes, net	—		108		1,236
Proceeds from issuance of term loan, net	—		1,455		—
Cash paid to purchase debt	(94)		(1,073)		(2,813)
Extinguishment of other financing	—		—		(122)
Cash paid for preferred stock dividends	(22)		(91)		(92)
Other	(13)		(36)		(33)
Net Cash Provided By (Used In) Financing Activities	101		859		(2,186)
Net increase (decrease) in cash and cash equivalents	273		2		(1)
Cash and cash equivalents, beginning of period	6		4		5
Cash and cash equivalents, end of period	$	279	$	6	$	4

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

	Years Ended December 31,
	2020		2019		2018
	($ in millions)
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for reorganization items, net	$	140	$	—	$	—
Interest paid, net of capitalized interest	$	224	$	691	$	664
Income taxes paid, net of refunds received	$	—	$	(6)	$	(3)

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in accrued drilling and completion costs	$	(216)	$	(19)	$	174
Put option premium on equity backstop agreement	$	60	$	—	$	—
Operating lease obligations recognized	$	32	$	—	$	—
Common stock issued for business combination	$	—	$	2,037	$	—
Debt exchanged for common stock	$	—	$	693	$	—
Preferred stock exchanged for common stock	$	—	$	40	$	—
Change in senior notes exchanged	$	—	$	971	$	—
Acquisition of other property and equipment including assets under finance lease	$	—	$	—	$	27

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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
PREFERRED STOCK:
Balance, beginning of period	$	1,631	$	1,671	$	1,671
Exchange/conversions of 100, 40,000 and 0 shares of preferred stock for common stock	—		(40)		—
Balance, end of period	1,631		1,631		1,671
COMMON STOCK:(a)
Balance, beginning of period	—		—		—
Common shares issued for WildHorse Merger	—		—		—
Exchange of senior notes and convertible notes	—		—		—
Balance, end of period	—		—		—
ADDITIONAL PAID-IN CAPITAL:(a)
Balance, beginning of period	16,973		14,387		14,446
Common shares issued for WildHorse Merger	—		2,037		—
Stock-based compensation	(14)		27		33
Exchange of contingent convertible notes for 0, 366,945 and 0 shares of common stock	—		135		—
Exchange of senior notes for 0, 1,177,817 and 0 shares of common stock	—		440		—
Exchange of preferred stock for 0, 51,839, and 0 shares of common stock	—		40		—
Equity component of contingent convertible notes repurchased	—		(2)		—
Dividends on preferred stock	(22)		(91)		(92)
Balance, end of period	16,937		16,973		14,387
RETAINED EARNINGS (ACCUMULATED DEFICIT):
Balance, beginning of period	(14,220)		(13,912)		(14,130)
Net income (loss) attributable to Chesapeake	(9,734)		(308)		226
Cumulative effect of change in accounting principle	—		—		(8)
Balance, end of period	(23,954)		(14,220)		(13,912)
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance, beginning of period	12		(23)		(57)
Hedging activity	33		35		34
Balance, end of period	45		12		(23)

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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY - (Continued)


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
TREASURY STOCK – COMMON:(a)
Balance, beginning of period	(32)		(31)		(31)
Purchase of 17,901, 14,391, and 7,550 shares for company benefit plans	(2)		(7)		(4)
Release of 44,126, 4,398 and 2,519 shares from company benefit plans	34		6		4
Balance, end of period	—		(32)		(31)
TOTAL STOCKHOLDERS’ EQUITY (DEFICIT)	(5,341)		4,364		2,092
NONCONTROLLING INTERESTS:
Balance, beginning of period	37		41		44
Net income attributable to noncontrolling interests	(16)		—		2
Distributions to noncontrolling interest owners	—		(4)		(5)
Divestiture of underlying assets	(21)		—		—
Balance, end of period	—		37		41
TOTAL EQUITY (DEFICIT)	$	(5,341)	$	4,401	$	2,133

(a) Amounts and shares have been retroactively adjusted to reflect a 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information.

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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

Chesapeake Energy Corporation ("Chesapeake", “we,” “our”, “us” or the "Company") is an oil and natural gas exploration and production company engaged in the acquisition, exploration and development of properties for the production of oil, natural gas and natural gas liquids (NGL) from underground reservoirs. Our operations are located onshore in the United States. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to February 9, 2021, and to the pre-emergence company as “Predecessor” for periods on or prior to February 9, 2021. As discussed in Note 2 below, we filed the Chapter 11 Cases on the Petition Date and subsequently operated as a debtor-in-possession, in accordance with applicable provisions of the Bankruptcy Code, until emergence on February 9, 2021.

Basis of Presentation

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

Accounting During Bankruptcy

We have applied Accounting Standards Codification (ASC) 852, Reorganizations, in preparing the consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the filing of a petition of Chapter 11 Cases, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred during the bankruptcy proceedings, including losses related to executory contracts that were approved for rejection by the Bankruptcy Court, and unamortized deferred financing costs, premiums and discounts associated with debt classified as liabilities subject to compromise, are recorded as reorganization items, net on our accompanying consolidated statements of operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the consolidated balance sheet as of December 31, 2020 as liabilities subject to compromise. These liabilities are reported at the amounts we anticipate will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. See Note 2 for more information regarding reorganization items.

Accounting Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the related disclosures in the financial statements. Management evaluates its estimates and related assumptions regularly, including those related to the impairment of oil and natural gas properties, oil and natural gas reserves, derivatives, income taxes, unevaluated properties not subject to evaluation, impairment of other property and equipment, environmental remediation costs, asset retirement obligations, litigation and regulatory proceedings and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ significantly from these estimates.

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Consolidation

We consolidate entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (“VIEs”) in which we are the primary beneficiary. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether we own a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements. We continually monitor our consolidated VIE to determine if any events have occurred that could cause the primary beneficiary to change. See Note 11 for further discussion of our VIE. We use the equity method of accounting to record our net interests where we have the ability to exercise significant influence through our investment but lack a controlling financial interest. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Undivided interests in oil and natural gas properties are consolidated on a proportionate basis.

Segments

Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating an enterprise’s resources and assessing its operating performance. We have concluded that we have only one reportable operating segment, which is exploration and production because our marketing activities are ancillary to our operations.

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 11 for further discussion of noncontrolling interests.

Cash and Cash Equivalents

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

Accounts Receivable

Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties deemed to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible. See Note 9 for further discussion of our accounts receivable.

Oil and Natural Gas Properties

We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, exploration costs such as exploratory geological and geophysical costs, expiration of unproved leasehold, delay rentals and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead and similar activities are also expensed as incurred. All property acquisition costs and development costs are capitalized when incurred.

Exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is

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being made in assessing the reserves and the economic and operational viability of the project. If we determine that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. We review the status of all suspended exploratory drilling costs quarterly. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of oil and natural gas are capitalized.

Costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are depreciated using the unit-of-production (“UOP”) method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves.

Proceeds from the sales of individual oil and natural gas properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depreciation, depletion and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

When circumstances indicate that the carrying value of proved oil and natural gas properties may not be recoverable, we compare unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820, Fair Value Measurements. If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted average cost of capital. We have classified these fair value measurements as Level 3 in the fair value hierarchy.

Other Property and Equipment

Other property and equipment consists primarily of buildings and improvements, land, vehicles, computers, a sand mine, natural gas compressors under finance lease and office equipment. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. Other property and equipment costs, excluding land, are depreciated on a straight-line basis and recorded within depreciation, depletion and amortization in the consolidated statement of operations. Natural gas compressors under finance lease are depreciated over the shorter of their estimated useful lives or the term of the related lease.

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. See Note 16 for further discussion of other property and equipment.

Capitalized Interest

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

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Accounts Payable

Included in accounts payable as of December 31, 2019 are liabilities of approximately $57 million representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. There were no corresponding liabilities as of December 31, 2020 due to our $279 million cash balance.

Debt Issuance Costs

Costs associated with the arrangement of our Exit Credit Facility were included in other long-term assets and will be amortized over the life of the facility using the straight-line method. The Exit Credit Facility unamortized issuance costs as of December 31, 2020 were $33 million and will begin amortization upon emergence from bankruptcy when the facility becomes fully available.

Costs associated with the issuance and amendments of our pre-petition revolving credit facility were included in other long-term assets and the remaining unamortized issuance costs were amortized over the life of the facility using the straight-line method. The remaining unamortized issuance costs as of December 31, 2019 totaled $27 million. Costs associated with the issuance of our senior notes were included in long-term debt and the remaining unamortized issuance costs were being amortized over the life of the senior notes using the effective interest method. The remaining unamortized issuance costs as of December 31, 2019 totaled $44 million. In 2020, our Chapter 11 Cases constituted an event of default under our pre-petition revolving credit facility and our senior notes, and non-cash adjustments were made to write off all related unamortized debt issuance costs which are included in reorganization items, net in the accompanying consolidated statements of operations for the year ended December 31, 2020. See Note 2 and Note 5 herein for further discussion of our Chapter 11 Cases and debt issuance costs, respectively.

Litigation Contingencies

We are subject to litigation and regulatory proceedings, claims and liabilities that arise in the ordinary course of business. We accrue losses associated with litigation and regulatory claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, our best estimate within the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or third-party recoveries. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 6 for further discussion of litigation contingencies.

Environmental Remediation Costs

We record environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized. See Note 6 for discussion of environmental contingencies.

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 22 for further discussion of asset retirement obligations.

Revenue Recognition

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

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

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

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

In circumstances where we act as an agent rather than a principal, our results of operations related to oil, natural gas and NGL marketing activities are presented on a net basis. See Note 9 for further discussion of revenue recognition.

Fair Value Measurements

Certain financial instruments are reported on a recurring basis at fair value on our consolidated balance sheets. We also use fair value measurements on a nonrecurring basis when a qualitative assessment of our assets indicates a potential impairment. 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. See Notes 5 and 14 for further discussion of fair value measurements.

Derivatives

Derivative instruments are recorded at fair value, and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. As of December 31, 2020, none of our open derivative instruments were designated as cash flow hedges.

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 which provide for the offsetting of asset and liability positions within each contract type, as well as

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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 14 for further discussion of our derivative instruments.

Share-Based Compensation

Our share-based compensation program consists of restricted stock, stock options, performance share units and cash restricted stock units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three 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 are 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 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 expense, oil, natural gas and NGL production expense, exploration expense, or marketing expense, based on the employees involved in those activities. See Note 12 for further discussion of share-based compensation.

Liability Management

Liability management expense includes third party legal and professional service fees incurred for our activities to restructure our debt and in preparation for our bankruptcy petition. As a result of our Chapter 11 Cases, such expenses, to the extent that they were incremental and directly related to our bankruptcy reorganization, are reflected in reorganization items, net in our consolidated statements of operations.

2. Chapter 11 Proceedings

On June 28, 2020, the Debtors filed voluntary petitions for relief under the Bankruptcy Code in the Bankruptcy Court. On June 29, 2020, the Bankruptcy Court entered an order authorizing the joint administration of the Chapter 11 Cases under the caption In re Chesapeake Energy Corporation, Case No. 20-33233. The Non-Filing Entities were not part of the Chapter 11 Cases. The Debtors and the Non-Filing Entities have continued to operate in the ordinary course of business during the Chapter 11 Cases.

The Bankruptcy Court confirmed the Plan in a bench ruling on January 13, 2021 and entered the Confirmation Order on January 16, 2021. The Debtors emerged from bankruptcy on February 9, 2021 (the “Effective Date”). Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession through the year ending December 31, 2020. As such, the Company’s bankruptcy proceedings and related matters have been summarized below.

Debtor-In-Possession

During the pendency of the Chapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted the first day relief we requested that was designed primarily to mitigate the impact of the Chapter 11 Cases on our operations, customers and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the period following the Petition Date and were also authorized to pay mineral interest owner royalties, employee wages and benefits, and certain vendors and suppliers in the ordinary course for goods and

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services provided prior to the Petition Date. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.

Automatic Stay

Subject to certain specific exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically stayed all judicial or administrative actions against us and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities were subject to compromise and discharge under the Bankruptcy Code. The automatic stay was lifted on the Effective Date.

Plan of Reorganization

In accordance with the Plan confirmed by the Bankruptcy Court, the following significant transactions occurred upon the Company’s emergence from bankruptcy on February 9, 2021:

On the Effective Date, we issued approximately 97,907,081 shares of the reorganized company (“New Common Stock”), reserved 2,092,918 shares of New Common Stock for future issuance to eligible holders of Allowed Unsecured Notes Claims and Allowed General Unsecured Claims and reserved 37,174,210 shares of New Common Stock for issuance upon exercise of the Warrants, which were the result of the transactions described below. We also entered into a registration rights agreement, a warrants agreement and amended our articles of incorporation and bylaws for the authorization of the New Common Stock and to provide registration rights thereunder, among other corporate governance actions. See Note 11 for further discussion of our post-emergence equity.
Each holder of a Predecessor equity interest in Chesapeake, including our common and preferred stock, had such interest canceled, released, and extinguished without any distribution.
Each holder of obligations under the pre-petition revolving credit facility received, at such holder's prior determined allocation, its pro rata share of either Tranche A Loans or Tranche B Loans, on a dollar for dollar basis.
Each holder of obligations under the FLLO Term Loan Facility received its pro rata share of 23,022,420 shares of New Common Stock.
Each holder of an Allowed Second Lien Notes Claim received its pro rata share of 3,635,118 shares of New Common Stock, 11,111,111 Class A Warrants to purchase 11,111,111 shares of New Common Stock, 12,345,679 Class B Warrants to purchase 12,345,679 shares of New Common Stock, and 6,858,710 Class C Warrants to purchase 6,858,710 shares of New Common Stock.
Each holder of an Allowed Unsecured Notes Claim received its pro rata share of 1,311,089 shares of New Common Stock and 2,473,757 Class C Warrants to purchase 2,473,757 shares of New Common Stock.
Each holder of Allowed General Unsecured Claim received its pro rata share of 231,112 shares of New Common Stock and 436,060 Class C Warrants to purchase 436,060 shares of New Common Stock; provided that to the extent such Allowed General Unsecured Claim is a Convenience Claim, such holder instead received its pro rata share of $10 million, which pro rata share shall not exceed five percent of such Convenience Claim.
Participants in the Rights Offering extending to the applicable classes under the Plan received 62,927,320 shares of New Common Stock.
In connection with the rights offering described above, the Backstop Parties under the Commitment Agreement received 6,337,031 shares of New Common Stock in respect to the Put Option Premium, and 442,991 shares of New Common Stock were issued in connection with the backstop obligation thereunder to purchase unsubscribed shares of the New Common Stock.

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2,092,918 shares of New Common Stock and 3,948,893 Class C Warrants were reserved for future issuance to eligible holders of Allowed Unsecured Notes Claims and Allowed General Unsecured Claims. The reserved New Common Stock and Class C Warrants will be issued on a pro rata basis upon the determination of the allowed portion of all disputed General Unsecured Claims and Unsecured Notes Claims.
The 2021 Long Term Incentive Plan (the “LTIP”) was approved with a share reserve equal to 6,800,000 shares of New Company Stock.
Each holder of an Allowed Other Secured Claim will receive, at the Company's option and in consultation with the Required Consenting Stakeholders (as defined in the Plan): (a) payment in full in cash; (b) the collateral securing its secured claim; (c) reinstatement of its secured claim; or (d) such other treatment that renders its secured claim unimpaired in accordance with Section 1124 of the Bankruptcy Code.
Each holder of an Allowed Other Priority Claim (as defined in the Plan) will receive cash up to the allowed amount of its claim.

Additionally, pursuant to the Plan confirmed by the Bankruptcy Court, the Company’s post-emergence Board of Directors is comprised of seven directors, including the Company’s Chief Executive Officer, Robert D. Lawler, and six non-employee directors, Michael Wichterich, Timothy S. Duncan, Benjamin C. Duster, IV, Sarah Emerson, Matthew M. Gallagher and Brian Steck.

DIP and Exit Credit Facilities

On June 28, 2020, prior to the commencement of the Chapter 11 Cases, the Company entered into a commitment letter (the “Commitment Letter”) with certain of the lenders under the pre-petition revolving credit facility and/or their affiliates (collectively, the “Commitment Parties”), pursuant to which, and subject to the satisfaction of certain customary conditions, including the approval of the Bankruptcy Court, the Commitment Parties agreed to provide the Debtors with a post-petition senior secured super-priority debtor-in-possession revolving credit facility in an aggregate principal amount of up to approximately $2.104 billion (the “DIP Credit Facility”), consisting of a revolving loan facility of new money in an aggregate principal amount of up to $925 million, which includes a sub-facility of up to $200 million for the issuance of letters of credit, and an up to approximately $1.179 billion term loan that reflects the roll-up of a portion of outstanding borrowings under the pre-petition revolving credit facility. Pursuant to the Commitment Letter, the Commitment parties have also committed to provide, subject to certain conditions, an up to $2.5 billion exit credit facility, consisting of an up to $1.75 billion revolving credit facility (the “Exit Revolving Facility”) and an up to $750 million senior secured term loan facility (the “Exit Term Loan Facility” and, together with the Exit Revolving Facility, the “Exit Credit Facilities”). The terms and conditions of the DIP Credit Facility are set forth in the Senior Secured Super-Priority Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) attached to the Commitment Letter. The proceeds of the DIP Credit Facility may be used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases, payment of court approved adequate protection obligations, and other such purposes consistent with the DIP Credit Facility. On the Effective Date, the DIP Credit Facility was terminated and the holders of obligations under the DIP Credit Facility received payment in full in cash; provided that to the extent such lender under the DIP Credit Facility is also a lender under the Exit Revolver, such lender’s allowed DIP claims were first reduced dollar-for-dollar and satisfied by the amount of its Exit RBL Loans provided as of the Effective Date.

Potential Claims

We filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of us and each of our Debtor subsidiaries, subject to the assumptions filed in connection therewith. Certain of these schedules and statements were amended after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the deadline for general claims, (the “bar date”), which was set by the Bankruptcy Court as October 30, 2020. Governmental units were required to file proof of claims by December 28, 2020, the deadline that was set by the Bankruptcy Court.

As of February 25, 2021, the Debtors had received approximately 8,100 proofs of claim, approximately 72% of which represent general unsecured claims, for an aggregate amount of approximately $42.7 billion. We will continue

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to evaluate these claims throughout the Chapter 11 process and recognize or adjust amounts in future financial statements as necessary using the best information available at such time. Differences between amounts scheduled by us and claims by creditors will ultimately be reconciled and resolved in connection with the claims resolution process. In light of the expected number of creditors, the claims resolution process may take considerable time to complete and has continued after our emergence from bankruptcy.

Fresh-Start Reporting

Upon emergence from bankruptcy on February 9, 2021, we expect to qualify for fresh-start reporting. In order to qualify for fresh start-reporting (i) the holders of existing voting shares of the Company prior to its emergence must receive less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the plan of reorganization must be less than the post-petition liabilities and allowed claims. Under the principles of fresh-start reporting, a new reporting entity will be considered to have been created, and, as a result, the Company will allocate the reorganization value of the Company to its individual assets, including property, plant and equipment, based on their estimated fair values. The process of estimating the fair value of the Company’s assets, liabilities and equity upon emergence is currently ongoing and, therefore, such amounts have not yet been finalized. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $3.5 billion to $4.7 billion.

Financial Statement Classification of Liabilities Subject to Compromise

The accompanying consolidated balance sheet as of December 31, 2020 includes amounts classified as liabilities subject to compromise, which represent liabilities we anticipate will be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material.

Liabilities subject to compromise includes amounts related to the rejection of various executory contracts and unexpired leases. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts and unexpired leases are rejected. The nature of many of the potential claims arising under our executory contracts and unexpired leases has not been determined at this time, and therefore, such claims are not reasonably estimable at this time and may be material.

The following table summarizes the components of liabilities subject to compromise included on our consolidated balance sheet as of December 31, 2020:


	December 31, 2020
	($ in millions)
Debt	$	7,166
Accounts payable	15
Accrued interest	235
Provision for contract rejection damages	729
Other liabilities	498
Liabilities subject to compromise	$	8,643

Reorganization Items, Net

We have incurred and will continue to incur significant expenses, gains and losses associated with our reorganization, primarily the write-off of unamortized debt issuance costs and related unamortized premiums and discounts, debt and equity financing fees, provision for allowed claims and legal and professional fees incurred subsequent to the Chapter 11 Filings for the reorganization process. Provision for allowed claims primarily represents damages from contract rejections and settlements attributable to the midstream savings requirement as

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stipulated by the Plan. The amount of these items, which are being expensed as incurred significantly affect our statements of operations.

The following table summarizes the components in reorganization items, net included in our consolidated statements of operations for the year ended December 31, 2020:


	Year Ended December 31, 2020
	($ in millions)
Provision for allowed claims	(879)
Write off of unamortized debt premiums (discounts)	518
Write off of unamortized debt issuance costs	(61)
Debt and equity financing fees	(145)
Loss on divested assets	(128)
Legal and professional fees	(113)
Gain on settlement of pre-petition accounts payable	15
Loss on settlement of pre-petition revenues payable	(3)
Reorganization items, net	$	(796)

Going Concern

During the Company’s bankruptcy proceedings and prior to the Bankruptcy Court’s entry of an order confirming the Debtors’ Plan of Reorganization, the Company’s ability to continue as a going concern was contingent upon, among other things, its ability to (i) develop and successfully implement a plan of reorganization and obtain creditor acceptance and confirmation under the Bankruptcy Code, (ii) achieve savings on certain midstream contracts through rejection or renegotiation of terms, (iii) achieve certain liquidity metrics, and (iv) obtain exit financing sources sufficient to meet the Company’s future obligations. The Company’s debt obligations and uncertainties related to the bankruptcy process raised substantial doubt about its ability to continue as a going concern.

As a result of the execution of the Plan of Reorganization and emergence from bankruptcy on February 9, 2021, management concluded there is no longer substantial doubt about the Company’s ability to continue as a going concern.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

3. Oil and Natural Gas Property Transactions

Mid-Continent Divestiture

On October 13, 2020, we filed a notice with the Bankruptcy Court that we reached an agreement with Tapstone Energy in a Section 363 transaction under the Bankruptcy Code. An auction supervised by the Bankruptcy Court was held on November 10, 2020 in which other pre-qualified buyers submitted bids for the asset. We presented the results of the auction process to the Bankruptcy Court and the sale was approved on November 13, 2020. On December 11, 2020, we closed the transaction with Tapstone Energy for $130 million, subject to post-closing adjustments which resulted in the recognition of a gain of approximately $27 million.

Haynesville Exchange

On November 22, 2020, we filed notice with the Bankruptcy Court that we had reached an agreement with Williams to transfer certain Haynesville assets, including interests in 144 producing wells and approximately 50,000 net acres, in exchange for improved midstream contract terms with respect to assets we retained. On December 15, 2020, the Court approved the transaction with Williams and the exchange resulted in the recognition of loss of approximately $128 million based on the difference between the carrying value of the assets and the fair value of the assets surrendered. The exchange was executed to obtain sufficient savings on midstream obligations as required by the Plan. Therefore, the loss was recorded to reorganization items, net in our consolidated statements of operations.

WildHorse Acquisition

On February 1, 2019, we acquired WildHorse Resource Development Corporation (“WildHorse”), an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas, for approximately 3.6 million reverse stock split-adjusted shares of our common stock and $381 million in cash. We funded the cash portion of the consideration through borrowings under the pre-petition revolving credit facility. In connection with the closing, we acquired all of WildHorse’s debt. See Note 5 for additional information on the acquired debt.

2019 Purchase Price Allocation

We have accounted for the acquisition of WildHorse and its corresponding merger (the “Merger”) with and into our wholly owned subsidiary, Brazos Valley Longhorn, L.L.C. (“Brazos Valley Longhorn” or “BVL”), as a business combination, using the acquisition method. The following table represents the final allocation of the total purchase price of WildHorse to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	2019 Purchase Price Allocation
	($ in millions)
Consideration:
Cash	$	381
Fair value of Chesapeake’s common stock issued in the Merger (a)	2,037
Total consideration	$	2,418

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

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

Total identifiable net assets	$	2,418

(a) Based on 3.6 reverse stock split-adjusted Chesapeake common shares issued at closing at $568 per share (closing price as of February 1, 2019).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The fair values of assets acquired and liabilities assumed were based on the following key inputs:

Oil and Natural Gas Properties

For the acquisition of WildHorse, we applied applicable guidance, under which an acquirer should recognize the identifiable assets acquired and the liabilities assumed on the acquisition date at fair value. The fair value estimate of proved and unproved oil and natural gas properties as of the acquisition date was based on estimated oil and natural gas reserves and related future net cash flows discounted using a weighted average cost of capital, including estimates of future production rates and future development costs. We utilized a combination of the NYMEX strip pricing and consensus pricing to value the reserves. Our estimates of commodity prices for purposes of determining discounted cash flows ranged from a 2019 price of $56.33 per barrel of oil increasing to a 2023 price of $61.17 per barrel of oil. Similarly, natural gas prices ranged from a 2019 price of $2.82 per mmbtu then increasing to a 2023 price of $3.00 per mmbtu. Both oil and natural gas commodity prices were held flat after 2023 and adjusted for inflation. We then applied various discount rates depending on the classification of reserves and other risk characteristics. Management utilized the assistance of a third-party valuation expert to estimate the value of the oil and natural gas properties acquired. Additionally, the estimated fair value estimate of proved and unproved oil and natural gas properties was corroborated by utilizing the market approach which considers recent comparable transactions for similar assets.

The inputs used to value oil and natural gas properties require significant judgment and estimates made by management and represent Level 3 inputs.

Financial Instruments and Other

The fair value measurements of long-term debt were estimated based on a market approach using estimates provided by an independent investment data services firm and represent Level 2 inputs.

Deferred Income Taxes

For federal income tax purposes, the WildHorse acquisition qualified as a tax-free merger, as a result, we acquired carryover tax basis in WildHorse’s assets and liabilities. Deferred tax liabilities and assets were recorded for differences between the purchase price allocated to the assets acquired and liabilities assumed based on the fair value and the carryover tax basis. See Note 10 for further discussion of deferred income taxes.

WildHorse Revenues and Expenses Subsequent to Acquisition

We included in our consolidated statements of operations revenues of $752 million, direct operating expenses of $810 million, including depreciation, depletion and amortization, and other expense of $83 million related to the WildHorse business for the period from February 1, 2019 to December 31, 2019.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Pro Forma Financial Information

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


	Years Ended December 31,
	2019		2018
	($ in millions except per share data)
Revenues	$	8,587	$	11,211
Net income (loss) available to common stockholders	$	(431)	$	195
Earnings (loss) per common share:(a)
Basic	$	(51.77)	$	42.89
Diluted	$	(51.77)	$	42.89

(a)All per share information has been retroactively adjusted to reflect the 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information.

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

2019 Transactions

In 2019, we received proceeds of approximately $130 million, net of post-closing adjustments, and recognized a gain of approximately $46 million, primarily for the sale of non-core oil and natural gas properties.

2018 Transactions

We sold all of our approximately 1,500,000 gross (900,000 net) acres in Ohio, of which approximately 320,000 net acres are prospective for the Utica Shale with approximately 920 producing wells, along with related property and equipment for net proceeds of $1.868 billion to Encino, with additional contingent payments to us of up to $100 million comprised of $50 million in consideration in each case if, on or prior to December 31, 2019, there is a period of twenty (20) trading days out of a period of thirty (30) consecutive trading days where (i) the average of the NYMEX natural gas strip prices for the months comprising the year 2022 equals or exceeds $3.00/mmbtu as calculated pursuant to the purchase agreement, and (ii) the average of the NYMEX natural gas strip prices for the months comprising the year 2023 equals or exceeds $3.25/mmbtu as calculated pursuant to the purchase agreement. The contingent consideration expired on December 31, 2019 with no value attributed to the arrangement. We recognized a loss of approximately $273 million associated with the transaction.

In 2018, we sold portions of our acreage, producing properties and other related property and equipment in the Mid-Continent, including our Mississippian Lime assets, for approximately $491 million, subject to certain customary closing adjustments. Included in the sales were approximately 238,500 net acres and interests in approximately 3,200 wells. We recognized a gain of approximately $12 million associated with the transactions. Also, in 2018, we received proceeds of approximately $37 million subject to customary closing adjustments, for the sale of other oil and natural gas properties covering various operating areas.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

4. Earnings Per Share

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

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

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


	Years Ended December 31,
	2020	2019	2018
	(thousands)
Common stock equivalent of our preferred stock outstanding(a)	290	290	298
Common stock equivalent of our convertible senior notes outstanding(a)	621	621	729
Common stock equivalent of our preferred stock outstanding prior to exchange(a)	—	5	—
Participating securities(a)	—	2	6

(a)Amount has been retroactively adjusted to reflect the 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information.

As a result of the Company’s reverse stock split effective on April 14, 2020, proportionate adjustments were made to the conversion price of Chesapeake’s outstanding 5.5% Convertible Senior Notes due 2026, 4.5% Cumulative Convertible Preferred Stock, 5.00% Cumulative Convertible Preferred Stock (Series 2005B), 5.75% Cumulative Convertible Non-Voting Preferred Stock (Series A) and 5.75% Cumulative Non-Voting Convertible Preferred Stock and to the outstanding awards and number of shares issued and issuable under the Company's equity compensation plans. See Note 11 for additional information.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. Debt

Chapter 11 Proceedings and Emergence

The Bankruptcy Filing constituted an event of default under certain of our secured and unsecured debt obligations. As a result of the Bankruptcy Filing, the principal and interest due under these debt instruments became immediately due and payable. However, pursuant to Section 362 of the Bankruptcy Code, the creditors were stayed from taking any action as a result of such defaults. On the Effective Date, our obligations under the FLLO Term Loan and Senior Notes, including interest and accrued interest, were fully extinguished in exchange for equity in the post-emergence Company. In addition, our pre-petition revolving credit facility was restructured into a new exit credit facility.

Reclassification of Debt

The principal amounts outstanding under the FLLO Term Loan, Second Lien Notes and all of our other unsecured senior and convertible senior notes were reclassified as liabilities subject to compromise on the accompanying consolidated balance sheet as of December 31, 2020. Additionally, non-cash adjustments were made to write off all of the related unamortized debt issuance costs and associated discounts and premiums of approximately $457 million, which are included in reorganization items, net in the accompanying consolidated statements of operations for the year ended December 31, 2020, as discussed in Note 2.

The agreements for our FLLO Term Loan, Second Lien Notes, and unsecured senior and convertible senior notes contain provisions regarding the calculation of interest upon default. Upon default, the interest rate on the FLLO Term Loan increased from LIBOR plus 8.00% to alternative base rate (ABR) (3.25% during the fourth quarter) plus Applicable Margin (7.00% during the fourth quarter) plus 2.00%. For the Second Lien Notes and all of our other unsecured senior and convertible senior notes, the interest rate remained the same upon default. However, interest accrued on the amount of unpaid interest in addition to the principal balance. We did not pay or recognize interest on the FLLO Term Loan, Second Lien Notes, or unsecured senior and convertible senior notes during the Chapter 11 process.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Pre-emergence debt

Our long-term debt consisted of the following as of December 31, 2020 and 2019:


	December 31, 2020				December 31, 2019
	Principal Amount		Carrying Amount		Principal Amount		Carrying Amount
	($ in millions)
DIP credit facility	$	—	$	—	$	—	$	—
Pre-petition revolving credit facility	1,929		1,929		1,590		1,590
Term loan due 2024	1,500		1,500		1,500		1,470
11.5% senior secured second lien notes due 2025	2,330		2,330		2,330		3,248
6.625% senior notes due 2020	176		176		208		208
6.875% senior notes due 2020	73		73		93		93
6.125% senior notes due 2021	167		167		167		167
5.375% senior notes due 2021	127		127		127		127
4.875% senior notes due 2022	272		272		338		338
5.75% senior notes due 2023	167		167		209		209
7.00% senior notes due 2024	624		624		624		624
6.875% senior notes due 2025	2		2		2		2
8.00% senior notes due 2025	246		246		246		245
5.5% convertible senior notes due 2026	1,064		1,064		1,064		765
7.5% senior notes due 2026	119		119		119		119
8.00% senior notes due 2026	46		46		46		44
8.00% senior notes due 2027	253		253		253		253
Debt issuance costs	—		—		—		(44)
Total debt, net	9,095		9,095		8,916		9,458
Less current maturities of long-term debt, net	(1,929)		(1,929)		(385)		(385)
Less amounts reclassified to liabilities subject to compromise	(7,166)		(7,166)		—		—
Total long-term debt, net	$	—	$	—	$	8,531	$	9,073

Debt Issuances and Retirements 2020

In 2020, we repurchased approximately $160 million aggregate principal amount of the following senior notes for $95 million and recorded an aggregate gain of approximately $65 million.


	Notes Repurchased
	($ in millions)
6.625% senior notes due 2020	$	32
6.875% senior notes due 2020	20
4.875% senior notes due 2022	66
5.75% senior notes due 2023	42
Total	$	160

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Debt Issuances and Retirements 2019

Term Loan. In December 2019, we entered into a secured 4.5-year term loan facility in an aggregate principal amount of $1.5 billion for net proceeds of approximately $1.455 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 and second lien notes (including BVL and its subsidiaries) 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 8.00% per annum, subject to a 1.00% LIBOR floor, or the Alternative Base Rate (ABR) plus 7.00% per annum, subject to a 2.00% ABR floor, at our option. The loan was made at 98% of par. We used the net proceeds to finance tender offers for our unsecured BVL senior notes and to repay amounts outstanding under our BVL revolving credit facility. We recorded an aggregate net gain of approximately $4 million associated with the retirement of our BVL senior notes and the BVL revolving credit facility.

The term loan matures in June 2024 and voluntary prepayments are subject to a make-whole premium prior to the 18-month anniversary of the closing of the term loan, a premium to par of 5.00% from the 18-month anniversary until but excluding the 30-month anniversary, a premium to par of 2.5% from the 30-month anniversary until but excluding the 42-month anniversary and at par beginning on the 42-month anniversary. The term loan may be subject to mandatory prepayments and offers to prepay 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.

Senior Secured Second Lien Notes. In December 2019, we completed private offers to exchange newly issued 11.5% Senior Secured Second Lien Notes due 2025 (the “Second Lien Notes”) for the following outstanding senior unsecured notes (the “Existing Notes”):


	Notes Exchanged
	($ in millions)
7.00% senior notes due 2024	$	226
8.00% senior notes due 2025	999
8.00% senior notes due 2026	873
7.5% senior notes due 2026	281
8.00% senior notes due 2027	837
Total	$	3,216

The Second Lien Notes are secured second lien obligations and are contractually junior to our current and future secured first lien indebtedness, including indebtedness incurred under our revolving credit facility and 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, make certain restricted payments, 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

independent of its subsidiaries. Chesapeake’s obligations under the Second Lien Notes are jointly and severally, fully and unconditionally guaranteed by the same subsidiaries that guarantee our revolving credit facility and term loan facility (including BVL and its subsidiaries). See Note 2 4 for condensed combined debtor financial information regarding our guarantor and non-guarantor subsidiaries.

The exchanges of the Existing Notes (with a carrying value of $3.152 billion) for $2.210 billion of Second Lien Notes, were accounted for as a troubled debt restructuring. For the majority of the notes in this exchange, the future undiscounted cash flows were greater than the net carrying value of the original debt, so no gain was recognized and a new effective interest rate was established based on the carrying value of the original debt. The amount of the extinguished debt will be amortized over the life of the notes as a reduction to interest expense. As a result, our reported interest expense will be significantly less than the contractual interest payments throughout the term of the Second Lien Notes.

In a subsequent transaction in December 2019, we issued an additional $120 million of 11.5% Senior Secured Second Lien Notes due 2025 pursuant to a private offering, at 89.75% of par. Additionally, in December 2019, we entered into a purchase and sale agreement with the same counterparty to acquire $101 million principal amount of our 6.625% Senior Notes due 2020, 4.875% Senior Notes due 2022 and 5.75% Senior Notes due 2023 at a discount. During the first quarter of 2020, we repurchased the senior notes.

Exchanges of Senior Notes for Common Stock. We privately negotiated exchanges of approximately $507 million principal amount of our outstanding senior notes for 235,563,519 shares of common stock and $186 million principal amount of our outstanding convertible senior notes for 73,389,094 shares of common stock. We recorded an aggregate net gain of approximately $64 million associated with the exchanges.

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


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

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

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

Debt Issuances and Retirements 2018

We issued at par $850 million of 7.00% Senior Notes due 2024 (“2024 notes”) and $400 million of 7.50% Senior Notes due 2026 (“2026 notes”) pursuant to a public offering for net proceeds of approximately $1.236 billion. We may redeem some or all of the 2024 notes at any time prior to April 1, 2021 and some or all of the 2026 notes at

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

any time prior to October 1, 2021, in each case at a price equal to 100% of the principal amount of the notes to be redeemed plus a “make-whole” premium. At any time prior to April 1, 2021, with respect to the 2024 notes, and October 1, 2021, with respect to the 2026 notes, we also may redeem up to 35% of the aggregate principal amount of each series of notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a specified redemption price. In addition, we may redeem some or all of the 2024 notes at any time on or after April 1, 2021 and some or all of the 2026 notes at any time on or after October 1, 2021, in each case at the redemption prices in accordance with the terms of the notes and the indenture and supplemental indenture governing the notes. These senior notes are unsecured obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Our obligations under the senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect wholly owned subsidiaries.

We used the net proceeds from the 2024 and 2026 notes, together with cash on hand and borrowings under the Chesapeake revolving credit facility, to repay in full $1.233 billion of borrowings under our secured term loan due 2021 for $1.285 billion, which included a $52 million make-whole premium. We recorded a loss of approximately $65 million associated with the repayment of the term loan, including the make-whole premium and the write-off of $13 million of associated deferred charges.

We used a portion of the proceeds from the sale of our Utica Shale assets in Ohio to redeem all of the $1.416 billion aggregate principal amount outstanding of our 8.00% Senior Secured Second Lien Notes due 2022 for $1.477 billion. We recorded a gain of approximately $331 million associated with the redemption, including the realization of the remaining $391 million difference in principal and book value due to troubled debt restructuring accounting in 2015, offset by the make-whole premium of $60 million.

We repaid upon maturity $44 million principal amount of our 7.25% Senior Notes due 2018.

As required by the terms of the indenture for our 2.25% Contingent Convertible Senior Notes due 2038 (“2038 notes”), the holders were provided the option to require us to purchase on December 15, 2018, all or a portion of the holders’ 2038 notes at par plus accrued and unpaid interest up to, but excluding, December 15, 2018. On December 17, 2018, we paid an aggregate of approximately $8 million to purchase all of the 2038 notes that were tendered and not withdrawn. An aggregate of $1 million principal amount of the 2038 notes remained outstanding as of December 31, 2018. Subsequent to December 31, 2018, we redeemed these notes at par and discharged the related indenture.

Senior Notes and Convertible Senior Notes

Our senior notes and our convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Our obligations under the senior notes and the convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect wholly owned subsidiaries. See Note 24 for consolidating financial information regarding our guarantor and non-guarantor subsidiaries.

Our senior notes, other than the convertible senior notes, were redeemable at any time at specified make-whole or redemption prices. Our senior notes were governed by indentures containing covenants that could 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 did not have any financial or restricted payment covenants. Indentures for the senior notes and convertible senior notes had cross default provisions that applied to other indebtedness Chesapeake or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million or $75 million, depending on the indenture.

Pre-Petition Revolving Credit Facility

Our revolving credit facility was scheduled to mature in September 2023 and the aggregate commitment of the lenders and borrowing base under the facility was $3.0 billion. The revolving credit facility provides for an accordion feature, pursuant to which the aggregate commitments thereunder may be increased to up to $4.0 billion from time to time, subject to agreement of the participating lenders and certain other customary conditions. As of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

December 31, 2020, we had outstanding borrowings of $1.929 billion under our revolving credit facility and had used $54 million for various letters of credit.

Borrowings under our revolving credit facility bear interest at an alternative base rate (ABR) or LIBOR, at our election, plus an applicable margin ranging from 1.50%-2.50% per annum for ABR loans and 2.50%-3.50% per annum for LIBOR loans, depending on the percentage of the borrowing base then being utilized.

Our revolving credit facility was subject to various financial and other covenants. The terms of the revolving credit facility included covenants limiting, among other things, our ability to incur additional indebtedness, make investments or loans, incur liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates.

On December 3, 2019, we entered into the second amendment to our credit agreement. Among other things, the amendment (i) permitted the issuance of certain secured indebtedness with a lien priority or proceeds recovery behind the obligations under the credit agreement without a corresponding 25% reduction in the borrowing base under the credit agreement, if issued by the next scheduled redetermination of the borrowing base, (ii) increased the amount of indebtedness that can be secured on a pari passu first-lien basis with (and with recovery proceeds behind) the obligations under the credit agreement from $1 billion to $1.5 billion, (iii) increased the applicable margin as defined in the credit agreement on borrowings under the credit agreement by 100 basis points, (iv) requires liquidity of at least $250 million at all times, (v) for each fiscal quarter commencing with the fiscal quarter ending December 31, 2019, replaced the secured leverage ratio financial covenant with a requirement that the first lien secured leverage ratio not exceed 2.50 to 1 as of the end of such fiscal quarter, (vi) increased the maximum permitted leverage ratio as of the end of each fiscal quarter to 4.50 to 1 through the fiscal quarter ending December 31, 2021, with step-downs to 4.25 to 1 for the fiscal quarter ending March 31, 2022 and to 4.00 to 1 for each fiscal quarter ending thereafter, and (vii) required that we use the aggregate net cash proceeds of certain asset sales in excess of $50 million to prepay certain indebtedness and/or reduce commitments under our credit agreement, until the retirement of all of our senior notes maturing before September 12, 2023. On December 26, 2019, we entered into the third amendment to our credit agreement, which, among other things, permitted the issuance of certain secured indebtedness with a lien priority behind the obligations under the credit agreement without a corresponding 25% reduction in the borrowing base under the credit agreement, if issued by December 31, 2019 and issued in exchange for, or the proceeds used to refinance, our senior notes.

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, 2020				December 31, 2019
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			($ in millions)
Short-term debt (Level 1)	$	—	$	—	$	385	$	360
Long-term debt (Level 1)	$	—	$	—	$	753	$	622
Long-term debt (Level 2)	$	—	$	—	$	8,320	$	6,085
Liabilities subject to compromise (Level 1)	$	982	$	43	$	—	$	—
Liabilities subject to compromise (Level 2)	$	6,184	$	1,694	$	—	$	—

Post-emergence Debt

Our post-emergence exit financing consists of a senior secured Exit Credit Facility, which includes a reserve-based revolving credit facility and a non-revolving loan facility, and unsecured senior notes, which all were entered into on the Effective Date. The initial outstanding principal amounts under the Exit Credit Facility and unsecured senior notes were:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	February 9, 2021
	($ in millions)
5.5% Senior Notes due 2026	$	500
5.875% Senior Notes due 2029	500
Exit Credit Facility - Exit Revolver	50
Exit Credit Facility - Non-Revolving Loan Facility	221
Total	$	1,271

Exit Credit Facility. On the Effective Date, pursuant to the terms of the Plan, the Company, as borrower, entered into a reserve-based credit agreement (the “Credit Agreement”) providing for a reserve-based credit facility (the “Exit Credit Facility”) with an initial borrowing base of $2.5 billion. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year and the next scheduled redetermination will be on or about October 1, 2021. The aggregate initial elected commitments of the lenders under the Exit Credit Facility will be $1.75 billion of revolving Tranche A Loans (the “Tranche A Loans”) and $220 million of fully funded Tranche B Loans (the “Tranche B Loans”).

The Exit Credit Facility provides for a $200.0 million sublimit of the aggregate commitments that are available for the issuance of letters of credit. The Exit Credit Facility bears interest at the ABR (alternate base rate) or LIBOR, at our election, plus an applicable margin (ranging from 2.25–3.25% per annum for ABR loans and 3.25–4.25% per annum for LIBOR loans, subject to a 1.00% LIBOR floor), depending on the percentage of the borrowing base then being utilized. The Tranche A Loans mature three years after the Effective Date and the Tranche B Loans mature four years after the Effective Date. The Tranche B Loans can be repaid if no Tranche A Loans are outstanding.

The Credit Agreement contains financial covenants that require the Company and its Guarantors, on a consolidated basis, to maintain (i) a first lien leverage ratio of not more than 2.75 to 1:00, (ii) a total leverage ratio of not more than 3.50 to 1:00, (iii) a current ratio of not less than 1.00 to 1:00 and (iv) at any time additional secured debt is outstanding, an asset coverage ratio of not less than 1.50 to 1:00, defined as PV10 of PDP reserves to total secured debt. The Company had no additional secured debt outstanding at emergence.

The Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments, and other customary covenants.

The Company is required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Tranche A Loans. The Company is also required to pay customary letter of credit and fronting fees.

Outstanding Senior Notes. On February 2, 2021, Chesapeake Escrow Issuer LLC (the “Escrow Issuer”) an indirect wholly-owned subsidiary of the Company, issued $500 million aggregate principal amount of its 5.5% Senior Notes due 2026 (the “2026 Notes”) and $500 million aggregate principal amount of its 5.875% Senior Notes due 2029 (the “2029 Notes” and, together with the 2026 Notes, the “Notes”). The offering of the Notes is part of a series of exit financing transactions being undertaken in connection with the Debtors’ Chapter 11 Cases and meant to provide the exit financing originally intended to be provided by the Exit Term Loan Facility pursuant to the Commitment Letter.

The Notes are guaranteed on a senior unsecured basis by each of the Company’s subsidiaries that guarantee the Exit Credit Facility. The gross proceeds from the offering of the Notes were deposited into a segregated escrow account (the “Escrow Account”) and were released upon satisfaction of certain escrow release conditions (the “Escrow Conditions”), including the occurrence of the Effective Date. Prior to the satisfaction of the Escrow Conditions, the Notes are secured by a lien on amounts deposited into the Escrow Account.

The Notes were issued pursuant to an indenture, dated as of February 5, 2021 (the “Indenture”), among the Issuer, the Guarantors and Deutsche Bank Trust Company Americas, as trustee.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Interest on the Notes will be payable semi-annually, on February 1st and August 1st of each year, commencing on August 1, 2021, to holders of record on the immediately preceding January 15th and July 15th.

The Notes are the Company’s senior unsecured obligations. Accordingly, they rank (i) equal in right of payment to all existing and future senior indebtedness, including borrowings under the Exit Credit Facility, (ii) effectively subordinate in right of payment to all of existing and future secured indebtedness, including indebtedness under the Exit Credit Facility, to the extent of the value of the collateral securing such indebtedness, (iii) structurally subordinate in right of payment to all existing and future indebtedness and other liabilities of any future subsidiaries that do not guarantee the notes and any entity that is not a subsidiary that does not guarantee the notes and (iv) senior in right of payment to all future subordinated indebtedness. Each guarantee of the notes by a guarantor is a general, unsecured, senior obligation of such guarantor. Accordingly, the guarantees (i) rank equally in right of payment with all existing and future senior indebtedness of such guarantor (including such guarantor’s guarantee of indebtedness under the Exit Credit Facility), (ii) are subordinated to all existing and future secured indebtedness of such guarantor, including such guarantor’s guarantee of indebtedness under our Exit Credit Facility, to the extent of the value of the collateral of such guarantor securing such secured indebtedness, (iii) are structurally subordinated to all indebtedness and other liabilities of any future subsidiaries of such guarantor that do not guarantee the notes and (iv) rank senior in right of payment to all future subordinated indebtedness of such guarantor.

6. Contingencies and Commitments

Contingencies

Chapter 11 Proceedings

Commencement of the Chapter 11 Cases automatically stayed the proceedings and actions against us that are described below, in addition to actions seeking to collect pre-petition indebtedness or to exercise control over the property of the Company’s bankruptcy estates. The Plan in the Chapter 11 Cases, which became effective on February 9, 2021, provided for the treatment of claims against the Company’s bankruptcy estates, including pre-petition liabilities that had not been satisfied or addressed during the Chapter 11 Cases. See Note 2 for additional information.

Litigation and Regulatory Proceedings

We were involved in a number of litigation and regulatory proceedings as of the Petition Date. Many of these proceedings were in early stages, and many of them sought damages and penalties, the amount of which is indeterminate. Our total accrued liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different. The majority of these prepetition legal proceedings, including the matters below, have been settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.

Business Operations. We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. The majority of these prepetition legal proceedings have been settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.

We and other natural gas producers have been named in various lawsuits alleging underpayment of royalties and other shares of the proceeds of production. The lawsuits against us allege, among other things, that we used below-market prices, made improper deductions, utilized improper measurement techniques, entered into arrangements with affiliates that resulted in underpayment of amounts owed in connection with the production and sale of natural gas and NGL, or similar theories. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The lawsuits seek compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief

regarding our payment practices, pre-and post-judgment interest, and attorney’s fees and costs. Royalty plaintiffs have varying provisions in their respective leases, oil and gas law varies from state to state, and royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations. We have resolved a number of these claims through negotiated settlements of past and future royalty obligations and have prevailed in various other lawsuits. We are currently defending numerous lawsuits seeking damages with respect to underpayment of royalties or other shares of the proceeds of production in multiple states where we have operated, including those discussed below.

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

Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the divestiture of substantially all of our midstream business and most of our gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights, intentional interference with contractual relations, and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources. These lawsuits seek in aggregate compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. On December 20, 2017 and August 9, 2018, we reached tentative settlements to resolve all Pennsylvania civil royalty cases for a total at that time of approximately $36 million. Subsequent to our Bankruptcy Filing the parties reopened settlement discussions.

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.

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

On January 29, 2020, a well control incident occurred at one of our wellsites in Burleson County, Texas, causing the deaths of three of our contractors’ employees and injuring a fourth. In connection with this incident, eleven lawsuits have been brought against us and our contractors alleging negligence, gross negligence, and breach of contract, and seeking wrongful death damages, survival statute damages, exemplary damages, and interest. Ten of the suits have been filed in Dallas County, Texas. A joint motion to consolidate filed by all the parties in nine of the ten Dallas County lawsuits is currently pending before the Texas Multidistrict Litigation Panel. The eleventh suit is pending in Burleson County, Texas. The proceedings are in their early stages and are all stayed due to the pending bankruptcy. Our general and excess liability insurance policies provide coverage for third party bodily injury and wrongful death claims, and the contracts between us and our contractors with respect to the well contain customary cross-indemnification provisions. The well control incident liability was not reduced for the potential insurance recovery and a receivable for the probable recovery was recorded.

Environmental Contingencies

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

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

We are in discussions with the Pennsylvania Department of Environmental Protection (PADEP) regarding gas migration in the vicinity of certain of our wells in Wyoming County, Pennsylvania. We believe we are close to identifying agreed-upon steps to resolve PADEP’s concerns regarding the issue. In addition to these steps, resolution of the matter may result in monetary sanctions of more than $300,000.

Other Matters

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

Commitments

Gathering, Processing and Transportation Agreements

We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of oil, natural gas and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Since filing the Chapter 11 Cases in June 2020, we have successfully renegotiated or terminated certain of our midstream contracts and commitments, including significantly reducing our gathering, processing and transportation expenses. Accordingly, $838 million of damages was accrued in liabilities subject to compromise. As of December 31, 2020, we were still negotiating certain of our midstream contracts pending our emergence from bankruptcy. 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.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	December 31, 2020
	($ in millions)
2021	$	865
2022	729
2023	596
2024	521
2025	471
2026 – 2034	1,911
Total	$	5,093

In addition, we have entered into long-term agreements for certain natural gas gathering and related services within specified acreage dedication areas in exchange for cost-of-service based fees redetermined annually, or tiered fees based on volumes delivered relative to scheduled volumes. Future gathering fees may vary with the applicable agreement.

Service Contract

We have contracts with third-party contractors to provide maintenance and other services to generators and natural gas compressors. These commitments are not recorded as an obligation in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future payments under these service contracts are detailed below.


	December 31, 2020
	($ in millions)
2021	$	7
2022	2
Total	$	9

Other Commitments

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

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

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

7. Other Liabilities

Other current liabilities as of December 31, 2020 and 2019 are detailed below:


	December 31,
	2020		2019
	($ in millions)
Revenues and royalties due others	$	236	$	516
Accrued drilling and production costs	104		326
Other accrued taxes	82		150
Debt and equity financing fees	69		—
Accrued compensation and benefits	59		156
Operating leases	24		9
Joint interest prepayments received	8		52
VPP deferred revenue(a)	—		55
Other	141		168
Total other current liabilities	$	723	$	1,432

Other long-term liabilities as of December 31, 2020 and 2019 are detailed below:


	December 31,
	2020		2019
	($ in millions)
VPP deferred revenue(a)	$	—	$	9
Other	5		116
Total other long-term liabilities	$	5	$	125

(a)At the inception of our volumetric production payment (VPP) agreements, we (i) removed the proved reserves associated with the VPP, (ii) recognized VPP proceeds as deferred revenue, which were being amortized on a unit-of-production basis to other revenue over the term of the VPP, (iii) retained responsibility for the production costs and capital costs related to VPP interests and (iv) ceased recognizing production associated with the VPP volumes. In 2020, we sold the assets related to our remaining VPP and extinguished the liability related to our production volume delivery obligation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

8. Leases

We are a lessee under various agreements for compressors, drilling rigs, vehicles and other equipment. As of December 31, 2020, these leases have remaining terms ranging from one month to three years. Certain of our lease agreements include options to renew the lease, terminate the lease early or purchase the underlying asset at the end of the lease. We determine the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when we are reasonably certain to exercise the option. The company’s vehicles are the only leases with renewal options that we are reasonably certain to exercise. The renewals are reflected in the ROU asset and lease liability balances.

Our operating ROU assets are included in other long-term assets while operating lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheet. Finance ROU assets are reflected in total property and equipment, net, while finance lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheet.

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

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

The following table presents our ROU assets and lease liabilities as of December 31, 2020 and 2019.


	Years Ended December 31,
	2020				2019
	Finance		Operating		Finance		Operating
	($ in millions)
ROU assets	$	9	$	29	$	17	$	22

Lease liabilities:
Current lease liabilities	$	9	$	27	$	9	$	9
Long-term lease liabilities	—		2		9		16
Total lease liabilities	9		29		18		25
Less amounts reclassified to liabilities subject to compromise	(9)		(5)		—		—
Total lease liabilities, net	$	—	$	24	$	18	$	25

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	Years Ended December 31,
	2020			2019
Lease cost:	($ in millions)
Amortization of ROU assets	$	9		$	8
Interest on lease liability	1			2
Finance lease cost	10			10
Operating lease cost	17			26
Short-term lease cost	32			112
Total lease cost	$	59		$	148

Other information:
Operating cash outflows from finance lease	$	1		$	2
Operating cash outflows from operating leases	$	9		$	11
Investing cash outflows from operating leases	$	40		$	127
Financing cash outflows from finance lease	$	9		$	8

	December 31,
	2020			2019
Weighted average remaining lease term - finance lease	1.00 year			2.00 years
Weighted average remaining lease term - operating leases	1.12 years			4.65 years
Weighted average discount rate - finance lease	7.50		%	7.50		%
Weighted average discount rate - operating leases	6.46		%	4.85		%

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


	December 31, 2020
	Finance Lease		Operating Leases
	($ in millions)
2021	$	10	$	28
2022	—		2
Total lease payments	10		30
Less imputed interest	(1)		(1)
Present value of lease liabilities	9		29
Less current maturities	(9)		(27)
Present value of lease liabilities, less current maturities	$	—	$	2

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

9. Revenue Recognition

The following table shows revenue disaggregated by operating area and product type, for the years ended December 31, 2020, 2019 and 2018:


	Year Ended December 31, 2020
	Oil		Natural Gas		NGL		Total
	($ in millions)
Marcellus	$	—	$	631	$	—	$	631
Haynesville	—		362		—		362
Eagle Ford	717		113		84		914
Brazos Valley	485		16		13		514
Powder River Basin	170		41		20		231
Mid-Continent	55		25		13		93
Revenue from contracts with customers	1,427		1,188		130		2,745
Gains on oil, natural gas and NGL derivatives	554		42		—		596
Oil, natural gas and NGL revenue	$	1,981	$	1,230	$	130	$	3,341

Marketing revenue from contracts with customers	$	1,195	$	494	$	110	$	1,799
Other marketing revenue	67		3		—		70
Marketing revenue	$	1,262	$	497	$	110	$	1,869

	Year Ended December 31, 2019
	Oil		Natural Gas		NGL		Total
	($ in millions)
Marcellus	$	—	$	856	$	—	$	856
Haynesville	—		620		—		620
Eagle Ford	1,289		153		119		1,561
Brazos Valley	721		32		16		769
Powder River Basin	369		77		32		478
Mid-Continent	164		44		25		233
Revenue from contracts with customers	2,543		1,782		192		4,517
Gains (losses) on oil, natural gas and NGL derivatives	(212)		217		—		5
Oil, natural gas and NGL revenue	$	2,331	$	1,999	$	192	$	4,522

Marketing revenue from contracts with customers	$	2,473	$	900	$	246	$	3,619
Other marketing revenue	311		41		—		352
Losses on marketing derivatives	—		(4)		—		(4)
Marketing revenue	$	2,784	$	937	$	246	$	3,967

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	Year Ended December 31, 2018
	Oil		Natural Gas		NGL		Total
	($ in millions)
Marcellus	$	—	$	924	$	—	$	924
Haynesville	2		836		—		838
Eagle Ford	1,514		173		185		1,872
Powder River Basin	244		68		38		350
Mid-Continent	246		84		55		385
Utica	195		401		224		820
Revenue from contracts with customers	2,201		2,486		502		5,189
Gains (losses) on oil, natural gas and NGL derivatives	124		(147)		(11)		(34)
Oil, natural gas and NGL revenue	$	2,325	$	2,339	$	491	$	5,155

Marketing revenue from contracts with customers	$	2,740	$	1,194	$	456	$	4,390
Other marketing revenue	457		222		—		679
Gains on marketing derivatives	—		7		—		7
Marketing revenue	$	3,197	$	1,423	$	456	$	5,076

Accounts Receivable

Accounts receivable as of December 31, 2020 and 2019 are detailed below:


	December 31,
	2020		2019
	($ in millions)
Oil, natural gas and NGL sales	$	589	$	737
Joint interest billings	119		200
Other	68		74
Allowance for doubtful accounts	(30)		(21)
Total accounts receivable, net	$	746	$	990

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

10. Income Taxes

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


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
Current
Federal	$	(3)	$	—	$	—
State	(6)		(26)		—
Current Income Taxes	(9)		(26)		—
Deferred
Federal	—		(297)		3
State	(10)		(8)		(13)
Deferred Income Taxes	(10)		(305)		(10)
Total	$	(19)	$	(331)	$	(10)

The income tax expense (benefit) reported in our consolidated statement of operations is different from the federal income tax expense (benefit) computed using the federal statutory rate for the following reasons:


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
Income tax expense (benefit) at the federal statutory rate of 21%	$	(2,051)	$	(134)	$	45
State income taxes (net of federal income tax benefit)	(41)		(21)		27
Partial release of valuation allowance due to the WildHorse Merger	—		(314)		—
Change in valuation allowance excluding impact of WildHorse Merger	2,010		114		(97)
Reorganization items	41		—		—
Equity-based compensation (non-officer)	10		4		4
Officer compensation limited under Section 162(m)	9		3		5
Other	3		17		6
Total	$	(19)	$	(331)	$	(10)

We applied the guidance in Staff Accounting Bulletin 118 when accounting for the enactment-date effect of the tax reform legislation commonly known as the Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 (the “Tax Act”). At December 31, 2017, we had not completed our accounting for all of the enactment-date income tax effects of the Tax Act under ASC 740, Income Taxes, for certain items as we were waiting on additional guidance to be issued. At December 31, 2018, we had completed our accounting for all of the enactment-date income tax effects of the Tax Act. The adjustments made during 2018 were considered immaterial but nevertheless are included as a component of income tax expense (benefit) in our consolidated statement of operations for the year ended December 31, 2018, which is fully offset with an adjustment to the valuation allowance against our net deferred tax asset position.

We reassessed the realizability of our deferred tax assets and continue to maintain a full valuation allowance against our net deferred tax asset positions for federal and state purposes. Of the net increase in our valuation allowance, $2.010 billion is reflected as a component of income tax expense in our consolidated statement of operations for the year ended December 31, 2020.

Deferred income taxes are provided to reflect temporary differences in the tax basis of assets and liabilities and their reported amounts in the financial statements. The tax-effected temporary differences, net operating loss

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(NOL) carryforwards and disallowed business interest carryforwards that comprise our deferred income taxes are as follows:


	December 31,
	2020		2019
	($ in millions)
Deferred tax liabilities:
Property, plant and equipment	$	—	$	(546)
Volumetric production payments	—		(89)
Derivative instruments	—		(14)
Other	(3)		(5)
Deferred tax liabilities	(3)		(654)

Deferred tax assets:
Property, plant and equipment	907		—
Net operating loss carryforwards	2,066		1,971
Carrying value of debt	48		169
Disallowed business interest carryforward	293		25
Asset retirement obligations	34		50
Investments	71		83
Accrued liabilities	288		64
Derivative instruments	53		—
Other	51		87
Deferred tax assets	3,811		2,449
Valuation allowance	(3,808)		(1,805)
Deferred tax assets after valuation allowance	3		644
Net deferred tax liability	$	—	$	(10)

As of December 31, 2020, we had federal NOL carryforwards of approximately $7.803 billion and state NOL carryforwards of approximately $7.784 billion. The associated deferred tax assets related to these federal and state NOL carryforwards were $1.639 billion and $427 million, respectively. The federal NOL carryforwards generated in tax years prior to 2018 expire in 2036 and 2037. As a result of the Tax Act, the 2018 through 2020 federal NOL carryforwards have no expiration. The value of all of these carryforwards depends on our ability to generate future taxable income.

As of December 31, 2020, and 2019, we had deferred tax assets of $3.811 billion and $2.449 billion upon which we had a valuation allowance of $3.808 billion and $1.805 billion, respectively. Of the net change in the valuation allowance of $2.003 billion for both federal and state deferred tax assets, $2.010 billion is reflected as a component of income tax benefit in the consolidated statement of operations and the difference is reflected in components of stockholders’ equity.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

A valuation allowance against deferred tax assets, including NOL carryforwards and disallowed business interest carryforwards, is recognized when it is more likely than not that all or some portion of the benefit from the deferred tax assets 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 existing taxable temporary differences, tax planning strategies, as well as the current and forecasted business economics of our industry. Management assesses all available evidence, both positive and negative, to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of objectively verifiable negative evidence is the cumulative loss incurred over the three-year period ended December 31, 2020. Such objective negative evidence limits our ability to consider various forms of subjective positive evidence, such as any projections for future income. Accordingly, management has not changed its judgment for the period ended December 31, 2020 with respect to the need for a full valuation allowance against our net deferred tax asset positions for federal and state purposes. The amount of the deferred tax assets considered realizable could be adjusted if projections of future taxable income are increased and/or if objective negative evidence in the form of cumulative losses is no longer present. Should we achieve a level of sustained profitability, consideration will need to be given to future projections of taxable income to determine whether such projections provide an adequate source of taxable income for the realization of our deferred tax assets, namely federal NOL carryforwards and disallowed business interest carryforwards. If so, then all or a portion of the valuation allowance could possibly be released.

On February 1, 2019, we completed the acquisition of WildHorse. For federal income tax purposes, the transaction qualified as a tax-free merger under Section 368 of the Code and, as a result, we acquired carryover tax basis in WildHorse’s assets and liabilities. We recorded a net deferred tax liability of $314 million as part of the business combination accounting for WildHorse. As a consequence of maintaining a full valuation allowance against our net deferred tax asset positions (federal and state), a partial release of the valuation allowance was recorded as a discrete income tax benefit of $314 million through the consolidated statement of operations in the first quarter of 2019. The net deferred tax liability determined through business combination accounting includes deferred tax liabilities on plant, property and equipment and prepaid compensation totaling $401 million, partially offset by deferred tax assets totaling $87 million relating to federal NOL carryforwards, disallowed business interest carryforwards and certain other deferred tax assets. These carryforwards will be subject to an annual limitation under Section 382 of the Code of approximately $61 million. We determined that no separate valuation allowances were required to be established through business combination accounting against any of the individual deferred tax assets acquired.

Our ability to utilize NOL carryforwards, disallowed business interest carryforwards, tax credits and possibly other tax attributes to reduce future taxable income and federal income tax is subject to various limitations under Section 382 of the Code. The utilization of such attributes may be subject to an annual limitation under Section 382 of the Code should transactions involving our equity result in a cumulative shift of more than 50% in the beneficial ownership of our stock during any three-year testing period (an “Ownership Change”). For this purpose, “stock” includes certain preferred stock. The annual limitation is generally equal to the product of (a) the fair market value of our equity immediately before the Ownership Change (i.e., the value of the old loss corporation) multiplied by (b) the long-term tax-exempt rate in effect for the month in which an Ownership Change occurs. If we are in a net unrealized built-in gain position at the time of an Ownership Change, then the limitation is increased by each year’s recognized built-in gains occurring within a five-year period following the Ownership Change, but only to the extent of the net unrealized built-in gain which existed at the time of the Ownership Change. However, proposed regulations issued on September 10, 2019, and on January 14, 2020, under Section 382(h) of the Code (the “Proposed Regulations”) would, if finalized in their present form, limit the potential increases to the annual limitation amount for certain built-in gains existing at the time of an Ownership Change, (unless the transition relief provisions of the Proposed Regulations are applicable), thereby possibly reducing the ability to utilize tax attributes significantly. If we are in a net unrealized built-in loss position at the time of an Ownership Change, then the limitation may apply to tax attributes other than just NOL carryforwards, disallowed business interest carryforwards and tax credits, such as tax depreciation, depletion and amortization. Some states impose similar limitations on tax attribute utilization upon experiencing an Ownership Change.

As of December 31, 2020, we do not believe that an Ownership Change had occurred that would subject us to an annual limitation on the utilization of our NOL carryforwards, disallowed business interest carryforwards, tax credits and possibly other tax attributes although our cumulative shift continues to be at a level greater than 40%.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Therefore, with the exception of the NOL carryforwards and disallowed business interest carryforwards acquired upon the WildHorse Merger, we do not believe we had a limitation on the ability to utilize our carryforwards and other tax attributes under Section 382 of the Code as of December 31, 2020. However, upon emergence from bankruptcy on February 9, 2021, the Company did experience an Ownership Change. If the old loss corporation is under the jurisdiction of the court in a case under Title 11 of the United States Code, then the annual limitation generally is based on the post-emergence fair market value of the equity of the new loss corporation as opposed to the fair market value of the equity of the old loss corporation. As such, an annual limitation will be computed based on the fair market value of the new equity immediately after emergence and will pertain to the post-emergence utilization of NOL carryforwards, disallowed business interest carryforwards and tax credits existing at the time of emergence.

Accounting guidance for recognizing and measuring uncertain tax positions requires a more likely than not threshold condition be met on a tax position, based solely on the technical merits of being sustained, before any benefit of the tax position can be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of uncertain tax positions. As of December 31, 2020, and 2019, the amount of unrecognized tax benefits related to NOL carryforwards and tax liabilities associated with uncertain tax positions was $74 million for both years. For both 2020 and 2019, $29 million is related to state tax receivables not expected to be recovered and the remainder is related to NOL carryforwards. If recognized, $29 million of the uncertain tax positions identified would have an effect on the effective tax rate. No material changes to the current uncertain tax positions are expected within the next 12 months. As of December 31, 2020, and 2019, we had no amounts accrued for interest related to these uncertain tax positions. We recognize interest related to uncertain tax positions as a component of interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses.

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


	2020		2019		2018
	($ in millions)
Unrecognized tax benefits at beginning of period	$	74	$	79	$	106
Additions based on tax positions related to the current year	—		—		—
Additions to tax positions of prior years	—		27		—
Settlements	—		(32)		—
Expiration of the applicable statute of limitations	—		—		(23)
Reductions to tax positions of prior years	—		—		(4)
Unrecognized tax benefits at end of period	$	74	$	74	$	79

Our federal and state income tax returns are subject to examination by federal and state tax authorities. Notification was received from the IRS during February 2021 that the examination of the WildHorse 2017 federal income tax return has been closed as a no-change audit. Further, the IRS has concluded the fieldwork relating to our 2016 federal income tax return with no changes proposed. Our tax years 2017 through 2019 remain open for all purposes of examination by the IRS as do the WildHorse 2018 federal income tax return and the WildHorse short period return for January 1, 2019, through February 1, 2019. However, certain earlier tax years remain open for adjustment to the extent of their NOL carryforwards available for future utilization.

In addition, tax years 2017 through 2019 as well as certain earlier years remain open for examination by state tax authorities. Currently, several state examinations are in progress of various years. We do not anticipate that the outcome of any federal or state audit will have a significant impact on our financial position or results of operations.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

11. Equity

Chapter 11 Proceedings

Upon our emergence from Chapter 11 on February 9, 2021, as discussed in Note 2, our then-authorized common stock and preferred stock were canceled and released under the Plan without receiving any recovery on account thereof.

Pre-Emergence Equity

Common Stock. A summary of the changes in our common shares issued for the years ended December 31, 2020, 2019 and 2018 is detailed below:


	Years Ended December 31,
	2020	2019	2018
	(in thousands)
Shares issued as of January 1(a)	9,773	4,568	4,543
Common shares issued for WildHorse Merger(a)(b)	—	3,587	—
Exchange of senior notes(a)(c)	—	1,178	—
Exchange of convertible notes(a)(c)	—	367	—
Exchange of preferred stock(a)	—	52	—
Restricted stock issuances (net of forfeitures and cancellations)(a)(d)	8	21	25
Shares issued as of December 31(a)	9,781	9,773	4,568

(a)All share information has been retroactively adjusted to reflect the 1-for-200 (1:200) reverse stock split effective April 14, 2020. See below for additional information.

(b)See Note 3 for discussion of WildHorse Merger.

(c)See Note 5 for discussion of debt exchanges.

(d)See Note 12 for discussion of restricted stock.

Reverse Stock Split. On April 13, 2020, our board of directors and our shareholders approved a 1-for-200 (1:200) reverse stock split of our common stock and a reduction of the total number of authorized shares of our common stock as determined by a formula based on two-thirds of the reverse stock split ratio. The reverse stock split became effective as of the close of business on April 14, 2020. Our common stock began trading on a split-adjusted basis on the NYSE at the market open on April 15, 2020. The par value of the common stock was not adjusted as a result of the reverse stock split.

The reverse stock split was intended to, among other things, increase the per share trading price of our common stock to satisfy the $1.00 minimum per share closing price requirement for continued listing on the NYSE. As a result of the reverse stock split, each 200 pre-split shares of common stock outstanding were automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled by paying cash in lieu of the fair value. The number of outstanding shares of common stock was reduced from approximately 1.957 billion as of April 10, 2020 to approximately 9.784 million shares (without giving effect to the liquidation of fractional shares). The total number of shares of common stock that we are authorized to issue was reduced from 3,000,000,000 to 22,500,000 shares. All share and per share amounts in the accompanying consolidated financial statements and notes thereto were retroactively adjusted for all periods presented to give effect to this reverse stock split, including reclassifying an amount equal to the reduction in par value of our common stock to additional paid-in capital.

During the year ended December 31, 2019, our shareholders approved a proposal to amend our restated certificate of incorporation to increase the number of authorized shares of our common stock from 15,000,000 shares to 22,500,000 shares, adjusted for our reverse stock split.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Cancellation of Rights Plan

On April 23, 2020, our Board of Directors declared a dividend of one Right payable on May 4, 2020 for each share of our common stock outstanding on May 4, 2020 to the shareholders of record on that date (the “Rights”). In connection with the distribution of the Rights, we entered into a Rights Agreement with Computershare Trust Company, N.A., as rights agent (the “Rights Agreement”). Each Right entitles the registered holder to purchase from us Preferred Shares.

The Rights Agreement was intended to protect value by preserving our ability to use our tax attributes to offset potential future income taxes for federal income tax purposes. Our ability to use our tax attributes would have been substantially limited if we had experienced an ownership change under Section 382 of the Code prior to emergence from bankruptcy on February 9, 2021. The Rights Agreement reduced the likelihood of an ownership change by deterring any person or group of affiliated or associated persons from acquiring beneficial ownership of 4.9% or more of the outstanding shares of our common stock.

In connection with the adoption of the Rights Agreement the Company filed a Certificate of Designations of Series B Preferred Stock with the Secretary of State of the State of Oklahoma setting forth the rights, powers, and preferences of the Series B Preferred Stock issuable upon exercise of the Rights (the “Preferred Shares”). On the Plan Effective Date, the Company filed a Certificate of Elimination with the Secretary of State of the State of Oklahoma eliminating the Preferred Shares and returning them to authorized but undesignated shares of the Company’s preferred stock. The foregoing is a summary of the terms of the Certificate of Elimination. The summary does not purport to be complete and is qualified in its entirety by reference to the Certificate of Elimination.

Preferred Stock. Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2020:


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	0.1984	$	5,039.59	May 17, 2015	$	6,551.46

5.75% (series A) cumulative convertible non-voting	May 2010	$	1,000	Any time	0.1918	$	5,215.02	May 17, 2015	$	6,779.52

4.50% cumulative convertible	September 2005	$	100	Any time	0.0123	$	8,142.99	September 15, 2010	$	10,585.89

5.00% cumulative convertible (series 2005B)	November 2005	$	100	Any time	0.0139	$	7,208.51	November 15, 2010	$	9,371.06

(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.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Outstanding shares of our preferred stock for the years ended December 31, 2020, 2019 and 2018 are detailed below:


	5.75%	5.75% (Series A)	4.50%	5.00% (Series 2005B)
	(in thousands)
Shares outstanding as of January 1, 2020 and December 31, 2020	770	423	2,559	1,811

Shares outstanding as of January 1, 2019	770	463	2,559	1,811
Preferred stock exchanges(a)	—	(40)	—	—
Shares outstanding as of December 31, 2019	770	423	2,559	1,811

Shares outstanding as of January 1, 2018 and December 31, 2018	770	463	2,559	1,811

(a)During 2019, we exchanged 51,839 shares of common stock for 40,000 shares of our 5.75% (Series A) Cumulative Convertible Preferred Stock. In connection with the exchange, 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 $17 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share.

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

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

On April 17, 2020, we announced that we were suspending payment of dividends on each series of our outstanding convertible preferred stock, and were therefore currently in arrears on such dividend payments as of December 31, 2020. Suspension of the dividends did not constitute an event of default under any of our debt instruments. No dividends have been accrued on our convertible preferred stock subsequent to the Petition Date. Pursuant to the Plan, each holder of an equity interest in Chesapeake had such interest canceled, released and extinguished without any distribution. See Note 2 for additional information about the Chapter 11 Cases.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Accumulated Other Comprehensive Income (Loss). For the years ended December 31, 2020 and 2019, changes in accumulated other comprehensive income (loss) for cash flow hedges, net of tax, are detailed below:


	Years Ended December 31,
	2020		2019
	($ in millions)
Balance, as of January 1	$	12	$	(23)
Amounts reclassified from accumulated other comprehensive income(a)	33		35
Balance, as of December 31	$	45	$	12

(a) Net losses on cash flow hedges for commodity contracts reclassified from accumulated other comprehensive income (loss), net of tax, to oil, natural gas and NGL revenues in the consolidated statements of operations.

Noncontrolling Interests. We owned 23,750,000 common units in the Chesapeake Granite Wash Trust (the “Trust”) representing a 51% beneficial interest. We determined that the Trust was a VIE and that we were the primary beneficiary. As a result, the Trust was included in our consolidated financial statements. In 2020, we sold our interests in the Mid-Continent operating area and the units we owned in the Trust. See Note 3 for additional discussion.

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

Post-Emergence Equity

New Common Stock. As discussed in Note 2, on the Effective Date, we issued an aggregate of approximately 97.9 million shares of New Common Stock, par value $0.01 per share, to the holders of allowed claims, as defined in the Plan, and approximately 2.1 million shares of New Common Stock were reserved for future distributions under the Plan.

Warrants. As discussed in Note 2, on the Emergence Date, we issued approximately 11.1 million Class A Warrants, 12.3 million Class B Warrants and 13.7 million Class C Warrants that are initially exercisable for one share of New Common Stock per Warrant at initial exercise prices of $27.63, $32.13 and $36.18 per share, respectively, subject to adjustments pursuant to the terms of the warrants. The warrants are exercisable from the Emergence Date until February 9, 2026. The warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions.

12. Share-Based Compensation

Our share-based compensation program has consisted of restricted stock, stock options, performance share units (PSUs) and cash restricted stock units (CRSUs) granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. The restricted stock and stock options were equity-classified awards and the PSUs and CRSUs were liability-classified awards.

Chapter 11 Proceedings

As discussed in Note 2, on the Effective Date, our current common stock was canceled and New Common Stock was issued. Accordingly, our then existing share-based compensation awards were also canceled, which resulted in the recognition of any previously unamortized expense related to the canceled awards on the date of cancellation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Share-Based Compensation Plans

2014 Long Term Incentive Plan. Our 2014 Long Term Incentive Plan (2014 LTIP), which is administered by the Compensation Committee of our Board of Directors, became effective on June 13, 2014 after it was approved by shareholders at our 2014 Annual Meeting. The 2014 LTIP replaced our Amended and Restated Long Term Incentive Plan which was adopted in 2005. The 2014 LTIP provides for up to 358,000 reverse stock split adjusted shares of common stock that may be issued as long-term incentive compensation to our employees and non-employee directors. 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. As of December 31, 2020, 474,123 reverse stock split adjusted shares of common stock remained issuable under the 2014 LTIP.

Equity-Classified Awards

Restricted Stock. We grant restricted stock to employees and non-employee directors. A summary of the changes in unvested restricted stock during 2020, 2019 and 2018 is presented below:


	Shares of Unvested Restricted Stock(a)	Weighted Average Grant Date Fair Value(a)
	(in thousands)
Unvested restricted stock as of January 1, 2020	52	$	710
Granted	68	$	60
Vested	(21)	$	792
Forfeited	(98)	$	243
Unvested restricted stock as of December 31, 2020	1	$	617

Unvested restricted stock as of January 1, 2019	59	$	886
Granted	30	$	530
Vested	(30)	$	876
Forfeited	(7)	$	744
Unvested restricted stock as of December 31, 2019	52	$	710

Unvested restricted stock as of January 1, 2018	66	$	1,274
Granted	30	$	746
Vested	(29)	$	1,534
Forfeited	(8)	$	1,204
Unvested restricted stock as of December 31, 2018	59	$	886

(a)Amount has been retroactively adjusted to reflect a 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information.

The aggregate intrinsic value of restricted stock that vested during 2020 was approximately $1 million based on the stock price at the time of vesting.

Stock Options. In 2020, 2019 and 2018, we granted members of management stock options that vest ratably over a three-year period. Each stock option award has an exercise price equal to the closing price of our common stock on the grant date. Outstanding options expire seven years to ten years from the date of grant.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method. Volatility assumptions are estimated based on the average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account our dividend policy, over the expected life of the option. We used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2019:


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

The following table provides information related to stock option activity for 2020, 2019 and 2018:


	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, 2020	90	$	1,420	5.70	$	—
Granted	—	$	—
Exercised	—	$	—		$	—
Expired	(23)	$	915
Forfeited	(47)	$	1,666
Outstanding as of December 31, 2020	20	$	1,429	4.27	$	—
Exercisable as of December 31, 2020	19	$	1,440	4.35	$	—

Outstanding as of January 1, 2019	90	$	1,440	7.15	$	—
Granted	5	$	594
Exercised	—	$	—		$	—
Expired	(2)	$	1,272
Forfeited	(3)	$	794
Outstanding as of December 31, 2019	90	$	1,420	5.70	$	—
Exercisable as of December 31, 2019	65	$	1,656	4.86	$	—

Outstanding as of January 1, 2018	81	$	1,650	7.73	$	1
Granted	18	$	602
Exercised	—	$	—		$	—
Expired	(3)	$	2,766
Forfeited	(6)	$	1,090
Outstanding as of December 31, 2018	90	$	1,440	7.15	$	—
Exercisable as of December 31, 2018	41	$	2,146	5.73	$	—

(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.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Restricted Stock and Stock Option Compensation. We recognized the following compensation costs, net of actual forfeitures, related to restricted stock and stock options for the years ended December 31, 2020, 2019 and 2018:


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
General and administrative expenses	$	20	$	26	$	31
Oil and natural gas properties	1		2		2
Oil, natural gas and NGL production expenses	1		3		5
Exploration expenses	—		1		1
Total restricted stock and stock option compensation	$	22	$	32	$	39

Liability-Classified Awards

Performance Share Units. In 2019, we granted PSUs to senior management that vest ratably over a three-year performance period and are settled in cash. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors. Compensation expense associated with PSU awards is recognized over the service period based on the graded-vesting method. The value of the PSU awards at the end of each reporting period is dependent upon our estimates of the underlying performance measures.

Cash Restricted Stock Units. In 2018, we granted CRSUs to employees that vest straight-line over a three-year period and are settled in cash on each of the three annual vesting dates. The ultimate amount earned is based on the closing price of our common stock on each of the vesting dates. We used the closing price of our common stock on the grant date to determine the grant date fair value of the CRSUs. The CRSU liability will be adjusted quarterly, based on changes in our stock price, through the end of the vesting period.

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


		Grant Date Fair Value			December 31, 2020
	Units(a)			Fair Value			Vested Liability
		($ in millions)			($ in millions)
2018 CRSU Awards:
Payable 2021	13,351	$	8		$	—		$	—

(a) Amount has been retroactively adjusted to reflect a 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We recognized the following compensation costs (credits), net of actual forfeitures, related to our liability-classified awards for the years ended December 31, 2020, 2019 and 2018:


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
General and administrative expenses	$	(3)	$	5	$	9
Oil and natural gas properties	—		1		1
Oil, natural gas and NGL production expenses	(1)		3		2
Separation and other termination costs	—		1		—
Total liability-classified awards compensation	$	(4)	$	10	$	12

2020 Compensation Adjustments

On May 5, 2020, all of the outstanding share-based compensation, including restricted stock, stock options, PSUs and CRSUs, granted to our executive officers and designated vice presidents was canceled and replaced with cash retention incentives. The cash retention incentives granted to executive officers are equally weighted between achievement of certain specified performance metrics and a service period. The cash retention incentives may be clawed back if an executive officer or vice president terminates employment for any reason other than a qualifying termination prior to the earlier of (i) the effective date of a plan of reorganization under Chapter 11 of the Bankruptcy Code or (ii) May 8, 2021. The transactions were considered a modification to the previously issued equity-classified awards. As such, the remaining unrecognized expense related to restricted stock and stock options will result in $18 million of share-based compensation expense to be amortized over the relevant service period of the new cash retention incentives. The $15 million after-tax fair value of the cash retention incentives was capitalized to other current assets in the consolidated balance sheets and will be amortized over the relevant service period. The difference between the cash and after-tax value of the cash retention incentives of approximately $10 million, which is not subject to the claw back provisions contained within the agreements, was expensed to general and administrative expenses in the consolidated statements of operations for the year ended December 31, 2020.

Post-Emergence Stock-Based Compensation

As of the Effective Date, the Board adopted the 2021 Long Term Incentive Plan (the 2021 LTIP) with a share reserve equal to 6,800,000 shares of New Common Stock. The 2021 LTIP provides for the grant of restricted stock units, restricted stock awards, stock options, stock appreciation rights, performance awards and other stock awards to the Company’s employees and non-employee directors.

13. Employee Benefit Plans

Our qualified 401(k) profit sharing plan (401(k) Plan) is the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, which is open to employees of Chesapeake and all our subsidiaries. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. We match employee contributions dollar for dollar (subject to a maximum contribution of 15% of an employee's base salary and performance bonus) in cash. We contributed $24 million, $29 million and $31 million to the 401(k) Plan in 2020, 2019 and 2018, respectively.

We also maintained a nonqualified deferred compensation plan (DC Plan) which we terminated in January 2020 in accordance with its terms. Accordingly, we derecognized the asset associated with the plan after the participants’ investments were liquidated. The cash was distributed to the participants, and we extinguished the corresponding $43 million accrued liability.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

14. Derivative and Hedging Activities

We use derivative instruments to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility. All of our oil, natural gas and NGL derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty. None of our open oil, natural gas and NGL derivative instruments were designated for hedge accounting as of December 31, 2020 and 2019.

Oil, Natural Gas and NGL Derivatives

As of December 31, 2020 and 2019, our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:

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

Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
Call Swaptions: We sell call swaptions to counterparties in exchange for a premium. Swaptions allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap.
Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The estimated fair values of our oil, natural gas and NGL derivative instrument assets (liabilities) as of December 31, 2020 and 2019 are provided below:


	December 31, 2020			December 31, 2019
	Notional Volume	Fair Value		Notional Volume	Fair Value
		($ in millions)			($ in millions)
Oil (mmbbl):
Fixed-price swaps	27	$	(136)	24	$	(7)
Collars	—	—		2	14
Basis protection swaps	7	(1)		8	(2)
Total oil	34	(137)		34	5
Natural gas (bcf):
Fixed-price swaps	728	10		265	125
Collars	53	8		—	—
Call options (sold)	—	—		22	—
Call swaptions	—	—		29	(2)
Basis protection swaps	66	1		30	2
Total natural gas	847	19		346	125
Total estimated fair value		$	(118)		$	130

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

Effect of Derivative Instruments – 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, 2020 and 2019 on a gross basis and after same-counterparty netting:


Balance Sheet Classification	Gross Fair Value		Amounts Netted in the Consolidated Balance Sheets		Net Fair Value Presented in the Consolidated Balance Sheets
	($ in millions)
As of December 31, 2020
Commodity Contracts:
Short-term derivative asset	$	84	$	(65)	$	19
Long-term derivative asset	5		(5)		—
Short-term derivative liability	(158)		65		(93)
Long-term derivative liability	(49)		5		(44)
Total derivatives	$	(118)	$	—	$	(118)

As of December 31, 2019
Commodity Contracts:
Short-term derivative asset	$	174	$	(40)	$	134
Short-term derivative liability	(42)		40		(2)
Long-term derivative liability	(2)		—		(2)
Total derivatives	$	130	$	—	$	130

As of December 31, 2020 and 2019, we did not have any cash collateral balances for these derivatives.

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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, 2020, 2019 and 2018 are presented below:


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
Oil, natural gas and NGL revenues	$	2,745	$	4,517	$	5,189
Gains on undesignated oil, natural gas and NGL derivatives	629		40		—
Losses on terminated cash flow hedges	(33)		(35)		(34)
Total oil, natural gas and NGL revenues	$	3,341	$	4,522	$	5,155

The components of marketing revenues for the years ended December 31, 2020, 2019 and 2018 are presented below:


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
Marketing revenues	$	1,869	$	3,971	$	5,069
Gains (losses) on undesignated marketing natural gas derivatives	—		(4)		7
Total marketing revenues	$	1,869	$	3,967	$	5,076

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,
	2020				2019				2018
	Before Tax		After Tax		Before Tax		After Tax		Before Tax		After Tax
	($ in millions)
Balance, beginning of period	$	(45)	$	12	$	(80)	$	(23)	$	(114)	$	(57)
Losses reclassified to income	33		33		35		35		34		34
Balance, end of period	$	(12)	$	45	$	(45)	$	12	$	(80)	$	(23)

The accumulated other comprehensive loss as of December 31, 2020 represents the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months are yet to occur. Remaining deferred gain or loss amounts will be recognized in earnings in the month for which the original contract months are to occur. As we early adopted ASU 2019-12 in 2020, the tax effect will be recognized in earnings in the year ended December 31, 2022. As of December 31, 2020, we expect to transfer approximately $8 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amounts will be transferred by December 31, 2022.

Credit Risk Considerations

Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are highly rated or deemed by us to have acceptable credit strength and deemed by management to be competent and competitive market-makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2020, our oil, natural gas and NGL derivative instruments were spread among 7 counterparties.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Hedging Arrangements

Certain of our hedging arrangements are with counterparties that were also lenders (or affiliates of lenders) under our DIP Credit Facility. The contracts entered into with these counterparties are secured by the same collateral that secures the pre-petition revolving credit facility. The counterparties’ obligations must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us exceed defined thresholds.

Fair Value

The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil, natural gas and NGL forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by our counterparties for reasonableness. Since oil, natural gas and NGL swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives.

The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2020 and 2019:


	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, 2020
Derivative Assets (Liabilities):
Commodity assets	$	—	$	78	$	10	$	88
Commodity liabilities	—		(204)		(2)		(206)
Total derivatives	$	—	$	(126)	$	8	$	(118)

As of December 31, 2019
Derivative Assets (Liabilities):
Commodity assets	$	—	$	160	$	14	$	174
Commodity liabilities	—		(42)		(2)		(44)
Total derivatives	$	—	$	118	$	12	$	130

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during 2020 and 2019 is presented below:


	Commodity Derivatives		Utica Contingent Consideration
	($ in millions)
Balance, as of January 1, 2020	$	12	$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)	11		—
Total purchases, issuances, sales and settlements:
Settlements	(15)		—
Balance, as of December 31, 2020	$	8	$	—

Balance, as of January 1, 2019	$	87	$	7
Total gains (losses) (realized/unrealized):
Included in earnings(a)	(59)		(7)
Total purchases, issuances, sales and settlements:
Settlements	(16)		—
Balance, as of December 31, 2019	$	12	$	—


(a)		Commodity Derivatives				Utica Contingent Consideration

		2020		2019		2020		2019
		($ in millions)
	Total gains (losses) included in earnings for the period	$	11	$	(59)	$	—	$	(7)
	Change in unrealized gains (losses) related to assets still held at reporting date	$	—	$	(19)	$	—	$	—

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

The significant unobservable inputs for Level 3 derivative contracts include market volatility. Changes in market volatility impact the fair value measurement of our derivative contracts, which is based on an estimate derived from option models. For example, an increase or decrease in the forward prices and volatility of oil and natural gas prices decreases or increases the fair value of oil and natural gas derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts as of December 31, 2020:


Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value December 31, 2020
				($ in millions)
Natural gas trades	Natural gas price volatility curves	24% – 71%	38%	$	8

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

15. Capitalized Exploratory Well Costs

A summary of the changes in our capitalized well costs for the years ended December 31, 2020, 2019 and 2018 is detailed below. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.


	Years Ended December 31,
	2020		2019		2018
	(in millions)
Balance as of January 1	$	7	$	36	$	36
Additions pending the determination of proved reserves	—		7		74
Divestitures and other	—		(3)		—
Reclassifications to proved properties	—		(17)		(40)
Charges to exploration expense	(7)		(16)		(34)
Balance as of December 31	$	—	$	7	$	36

The following table provides an aging of capitalized costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.


	2020		2019		2018
	(in millions)
Exploratory well costs capitalized for a period of one year or less	$	—	$	7	$	34
Exploratory well costs capitalized for a period greater than one year	—		—		2
Balance as of December 31	$	—	$	7	$	36

Number of projects with exploratory well costs capitalized for a period greater than one year	—		—		7

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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
	2020		2019
	($ in millions)				(in years)
Buildings and improvements	$	1,038	$	1,058	10 – 39
Computer equipment	356		355		5
Sand mine	81		78		10 – 30
Natural gas compressors(a)	36		48		3 – 20
Land	113		115
Other	130		156		5 – 20
Total other property and equipment, at cost	1,754		1,810
Less: accumulated depreciation	(799)		(692)
Total other property and equipment, net	$	955	$	1,118

(a) Includes assets under finance lease of $27 million, less accumulated depreciation of $18 million and $10 million, as of December 31, 2020 and 2019, respectively. The related amortization expense for assets under finance lease is included in depreciation, depletion and amortization expense on our consolidated statement of operations.

17. Investments

FTS International, Inc. (NYSE: FTSI). In 2018, FTS International, Inc. completed an initial public offering. Due to the offering, the ownership percentage of our equity method investment in FTSI decreased from approximately 29% to 24% and resulted in a gain of $78 million. In addition, we sold approximately 4.3 million shares of FTSI in the offering for net proceeds of approximately $74 million and recognized a gain of $61 million decreasing our ownership percentage to approximately 20%.

In 2019, the hydraulic fracturing industry experienced challenging operating conditions resulting in the current fair value of our investment in FTSI falling below book value of $65 million and remaining below that amount as of the end of the year. Based on FTSI’s 2019 operating results and FTSI’s share price of $1.04 per share as of December 31, 2019, we determined that the reduction in fair value is other-than-temporary, and recognized an impairment of our investment in FTSI of approximately $43 million.

In 2020, the hydraulic fracturing industry continued experiencing challenging operating conditions resulting in FTSI filing for Chapter 11 bankruptcy and we recognized an impairment of our entire investment of $23 million. FTSI emerged from bankruptcy on November 19, 2020 and this restructuring resulted in a reduction of the common stock we owned in FTSI from 20% to less than 2%. The decreased ownership percentage and the loss of significant influence required us to measure the investment at fair value as of December 31, 2020.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

18. Impairments

Impairments of Oil and Natural Gas Properties

A summary of our impairments of oil and natural gas properties for the years ended December 31, 2020, 2019 and 2018 is as follows:


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
Impairments due to lower forecasted commodity prices	$	8,446	$	8	$	23
Impairments due to anticipated sale	—		—		55
Total impairments of oil and natural gas properties	$	8,446	$	8	$	78

During 2020, the decrease in demand for crude oil primarily due to the combined impacts of COVID-19 and the OPEC+ production increases resulted in decreases in current and expected long-term crude oil and NGL sale prices. These conditions resulted in reductions to the market capitalization of peer companies in the energy industry. We determined these adverse market conditions represented a triggering event to perform an impairment assessment of our long-lived assets used in, and in support of, our operations, including proved oil and gas properties, and our sand mine assets.

Proved Oil and Gas Properties

Our impairment test involved a Step 1 assessment to determine if the net book value of our proved oil and natural gas properties is expected to be recovered from the estimated undiscounted future cash flows.

We calculated the expected undiscounted future net cash flows of our long-lived assets using management’s assumptions and expectations of (i) commodity prices, which are based on the NYMEX strip pricing escalated by an inflationary rate after 2 years, (ii) pricing adjustments for differentials, (iii) operating costs, (iv) capital investment plans, (v) future production volumes, and (vi) estimated proved reserves.
Unprecedented volatility in the price of oil due to the decrease in demand has led us to rely on NYMEX strip pricing, which represents a Level 1 input.

Certain oil and gas properties in our Eagle Ford, Brazos Valley, Powder River Basin, and Mid-Continent and other non-core operating areas failed the Step 1 assessment. For these assets, we used a discounted cash flow analysis to estimate fair value. The expected future net cash flows were discounted using a rate of 11%, which we believe represents the estimated weighted average cost of capital of a theoretical market participant. Based on Step 2 of our long-lived assets impairment test, we recognized an $8.446 billion impairment because the carrying value exceeded estimated fair market value as of March 31, 2020.

Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices escalated by an inflationary rate after two years, adjusted for differentials, and (v) a market-based weighted average cost of capital. We utilized NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs used are classified as Level 1 fair value assumptions and all other inputs are classified as Level 3 fair value assumptions.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Impairments of Fixed Assets

A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2020, 2019 and 2018 is as follows:


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
Sand mine	$	76	$	—	$	—
Natural gas compressors	13		—		45
Buildings and land	—		1		4
Other	—		2		4
Total impairments of fixed assets and other	$	89	$	3	$	53

In 2020, we recorded a $76 million impairment of our sand mine assets that support our Brazos Valley operating area for the difference between the fair value and carrying value of the assets as well as a $13 million impairment of compressor inventory due to a lack of a current market for compressors. In 2018, we recorded a $45 million impairment related to 890 compressors for the difference between carrying value and the fair value of the assets.

19. Exploration Expense

A summary of our exploration expense for the years ended December 31, 2020, 2019 and 2018 is as follows:


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
Impairments of unproved properties	$	411	$	32	$	59
Dry hole expense	7		25		37
Geological and geophysical expense and other	9		27		66
Exploration expense	$	427	$	84	$	162

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects. The exploration expense charges during 2020 are primarily the result of non-cash impairment charges in unproved properties, primarily in our Brazos Valley, Haynesville, Powder River Basin and Mid-Continent operating areas. The decrease in geological and geophysical expense in 2019 and 2020 was due to fewer exploratory geological and geophyscial projects.

20. Other Operating Expense

In 2020, we terminated certain gathering, processing and transportation contracts and recognized a non-recurring $80 million expense related to the contract terminations. The contract terminations removed approximately $169 million of future commitments related to gathering, processing and transportation agreements.

In 2019, we recorded approximately $37 million of costs related to our acquisition of WildHorse which consisted of consulting fees, financial advisory fees, legal fees and travel and lodging expenses. In addition, we recorded approximately $38 million of severance expense as a result of the acquisition of WildHorse. A majority of the WildHorse executives and employees were terminated on the date of acquisition. These executives and employees were entitled to severance benefits in accordance with existing employment agreements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

21. Separation and Other Termination Costs

Workforce Reductions

In 2020, 2019 and 2018, we incurred charges of approximately $44 million, $12 million and $38 million related to one-time termination benefits for certain employees.

Subsequent to December 31, 2020, we reduced our workforce by 220 employees or approximately 15%, primarily in Oklahoma City and incurred charges of approximately $20 million.

22. Asset Retirement Obligations

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


	Years Ended December 31,
	2020		2019
	($ in millions)
Asset retirement obligations, beginning of period	$	211	$	166
Additions(a)	1		21
Revisions	(14)		18
Settlements and disposals(b)	(66)		(5)
Accretion expense	12		11
Asset retirement obligations, end of period	144		211
Less current portion	5		11
Asset retirement obligation, long-term	$	139	$	200

(a) During 2019, approximately $17 million of additions relate to the acquisition of WildHorse.

(b) During 2020, approximately $49 million and $14 million of disposals related to our Mid-Continent and Haynesville assets, respectively. See Note 3 for further discussion of these transactions.

23. Major Customers

Sales to Valero Energy Corporation constituted approximately 17%, 12% and 10% of total revenues (before the effects of hedging) for the years ended December 31, 2020, 2019 and 2018, respectively. No other purchasers accounted for more than 10% of our total revenues in 2020, 2019 or 2018.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

24. Condensed Combined Debtor-in-Possession Financial Information

The financial statements below represent the combined financial statements of the Debtors as of December 31, 2020 and 2019 and the years ended December 31, 2020, 2019 and 2018.


Condensed Combined Balance Sheets	Total Combined Debtor Entities
	December 31,
	2020		2019
	($ in millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	278	$	4
Other current assets	829		1,244
Total Current Assets	1,107		1,248
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on successful efforts accounting, net	4,277		13,586
Other property and equipment, net	955		1,118
Property and equipment held for sale, net	10		10
Total Property and Equipment, Net	5,242		14,714
Other long-term assets	234		187
Investments in subsidiaries and intercompany advances	1		6
TOTAL ASSETS	$	6,584	$	16,155

LIABILITIES AND EQUITY (DEFICIT):
CURRENT LIABILITIES:
Current liabilities	$	3,094	$	2,391
Total Current Liabilities	3,094		2,391
Long-term debt, net	—		9,073
Deferred income tax liabilities	—		10
Other long-term liabilities	188		317
Liabilities subject to compromise	8,643		—
Total Liabilities	11,925		11,791
EQUITY (DEFICIT):
Stockholders’ equity (deficit)	(5,341)		4,364
Total Equity (Deficit)	(5,341)		4,364
TOTAL LIABILITIES AND EQUITY (DEFICIT)	$	6,584	$	16,155

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Condensed Combined Statements of Operations	Total Combined Debtor Entities
	Years Ended December 31,
	2020		2019		2018
	($ in millions)
REVENUES AND OTHER:
Oil, natural gas and NGL	$	3,334	$	4,508	$	5,136
Marketing	1,869		3,967		5,076
Total Revenues	5,203		8,475		10,212
Other	56		63		63
Gains (losses) on sales of assets	30		43		(264)
Total Revenues and Other	5,289		8,581		10,011
OPERATING EXPENSES:
Oil, natural gas and NGL production	373		520		474
Oil, natural gas and NGL gathering, processing and transportation	1,079		1,076		1,391
Severance and ad valorem taxes	149		224		188
Exploration	427		84		162
Marketing	1,889		4,003		5,158
General and administrative	266		314		334
Separation and other termination costs	44		12		38
Provision for legal contingencies	27		19		26
Depreciation, depletion and amortization	1,095		2,258		1,730
Impairments	8,501		11		131
Other operating expense	109		92		—
Total Operating Expenses	13,959		8,613		9,632
INCOME (LOSS) FROM OPERATIONS	(8,670)		(32)		379
OTHER INCOME (EXPENSE):
Interest expense	(331)		(651)		(633)
Gains (losses) on investments	(20)		(71)		139
Gains on purchases or exchanges of debt	65		75		263
Other income	16		39		67
Reorganization items, net	(796)		—		—
Equity in net earnings (losses) of subsidiary	(17)		1		1
Total Other Expense	(1,083)		(607)		(163)
INCOME (LOSS) BEFORE INCOME TAXES	(9,753)		(639)		216
INCOME TAX BENEFIT	(19)		(331)		(10)
NET INCOME (LOSS)	(9,734)		(308)		226
Other comprehensive income	33		35		34
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	(9,701)	$	(273)	$	260

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Condensed Combined Statements of Cash Flows	Total Combined Debtor Entities
	Years Ended December 31,
	2020		2019		2018
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	$	1,163	$	1,618	$	1,727

CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(1,111)		(2,180)		(1,848)
Business combination, net	—		(353)		—
Acquisitions of proved and unproved properties	(9)		(35)		(128)
Proceeds from divestitures of proved and unproved properties	136		130		2,231
Additions to other property and equipment	(22)		(48)		(21)
Proceeds from sales of other property and equipment	14		6		147
Proceeds from sales of investments	—		—		74
Net Cash Provided By (Used In) Investing Activities	(992)		(2,480)		455

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from pre-petition revolving credit facility borrowings	3,656		10,676		11,697
Payments on pre-petition revolving credit facility borrowings	(3,317)		(10,180)		(12,059)
Proceeds from DIP credit facility borrowings	60		—		—
Payments on DIP credit facility borrowings	(60)		—		—
DIP credit facility and exit facilities financing costs	(109)
Proceeds from issuance of senior notes, net	—		108		1,236
Proceeds from issuance of term loan, net	—		1,455		—
Cash paid to purchase debt	(94)		(1,073)		(2,813)
Cash paid for preferred stock dividends	(22)		(91)		(92)
Other financing activities	(11)		(32)		(149)
Intercompany advances, net	—		—		(2)
Net Cash Provided by (Used In) Financing Activities	103		863		(2,182)
Net increase in cash and cash equivalents	274		1		—
Cash and cash equivalents, beginning of period	4		3		3
Cash and cash equivalents, end of period	$	278	$	4	$	3

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

25. Subsequent Events

On February 2, 2021, an indirect wholly-owned subsidiary of the Company, issued $500 million aggregate principal amount of its 2026 Notes and $500 million aggregate principal amount of its 2029 Notes as part of a series of exit financing transactions being undertaken in connection with the Debtors’ Chapter 11 Cases and meant to provide the exit financing originally intended to be provided by the Exit Term Loan Facility pursuant to the Commitment Letter. Additionally, on the Effective Date, we entered into the Exit Credit Facility, a reserve-based credit facility with an initial borrowing base of $2.5 billion collateralized by our oil and gas properties. The aggregate initial elected commitments of the lenders under the Exit Credit Facility will be $1.75 billion of revolving Tranche A Loans and $220 million of fully funded Tranche B Loans on the Effective Date. See Note 5 for more information on our exit facilities.

On February 3, 2021, we reduced our workforce by 220 employees or approximately 15%, primarily in Oklahoma City and incurred charges of approximately $20 million. See Note 21 for more information regarding our workforce reduction.

We completed our financial restructuring and emerged from Chapter 11 bankruptcy proceedings on February 9, 2021. In support of the Plan, the enterprise value of the Successor was estimated and approved by the Bankruptcy Court to be in the range of $3.5 billion to $4.7 billion. We cannot currently estimate the financial effect of emergence from bankruptcy on our financial statements, although we expect to record material adjustments related to our Plan and the application of fresh-start reporting guidance upon the Effective Date. See Note 2 for more information regarding Chapter 11 proceedings including effects of the Plan.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

Quarterly Financial Data (unaudited)

Summarized unaudited quarterly financial data for 2020 and 2019 are as follows:


	2020 First Quarter(a)		2020 Second Quarter		2020 Third Quarter		2020 Fourth Quarter
	($ in millions except per share data)
Total revenues	$	2,541	$	521	$	975	$	1,259
Income (loss) from operations	$	(8,227)	$	(541)	$	(111)	$	176
Net loss attributable to Chesapeake	$	(8,297)	$	(276)	$	(745)	$	(416)
Net loss available to common stockholders	$	(8,319)	$	(276)	$	(745)	$	(416)

Net loss per common share(b):
Basic	$	(852.97)	$	(28.22)	$	(76.18)	$	(42.54)
Diluted	$	(852.97)	$	(28.22)	$	(76.18)	$	(42.54)


	2019 First Quarter		2019 Second Quarter		2019 Third Quarter		2019 Fourth Quarter
	($ in millions except per share data)
Total revenues	$	2,196	$	2,386	$	2,087	$	1,926
Income (loss) from operations	$	(182)	$	278	$	46	$	(173)
Net income (loss) attributable to Chesapeake	$	(21)	$	98	$	(61)	$	(324)
Net income (loss) available to common stockholders	$	(44)	$	75	$	(101)	$	(346)

Net income (loss) per common share(b):
Basic	$	(6.37)	$	9.21	$	(11.89)	$	(35.53)
Diluted	$	(6.37)	$	9.21	$	(11.89)	$	(35.53)

(a)Includes $8.446 billion of impairment charges as a result of the decrease in demand for crude oil primarily due to COVID-19 and sharp decline in commodity prices related to the combined impact of falling demand and increases in production from OPEC+ which resulted in decreases in crude oil and NGL sales prices.

(b)All per share information has been retroactively adjusted to reflect the 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

SUPPLEMENTARY INFORMATION - (Continued)

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

Net Capitalized Costs

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


	December 31,
	2020		2019
	($ in millions)
Oil and oil and natural gas properties:
Proved	$	25,734	$	30,765
Unproved	1,550		2,173
Total	27,284		32,938
Less accumulated depreciation, depletion and amortization	(23,007)		(19,310)
Net capitalized costs	$	4,277	$	13,628

Unproved properties as of December 31, 2020 and 2019, consisted mainly of leasehold acquired through direct purchases of significant oil and natural gas property interests. 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, including capitalized interest and asset retirement costs, are summarized as follows:


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
Acquisition of Properties(a):
Proved properties	$	3	$	3,264	$	80
Unproved properties	6		792		56
Exploratory costs	8		42		80
Development costs	887		2,177		1,954
Costs incurred	$	904	$	6,275	$	2,170

(a) Includes $3.264 billion and $756 million of proved and unproved property acquisitions, respectively, related to our acquisition of WildHorse in 2019.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

SUPPLEMENTARY INFORMATION - (Continued)

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

Our results of operations from oil, natural gas and NGL producing activities are presented below for 2020, 2019 and 2018. 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,
	2020		2019		2018
	($ in millions)
Oil, natural gas and NGL sales	$	3,341	$	4,522	$	5,155
Other revenue	56		63		63
Oil, natural gas and NGL production expenses	(373)		(520)		(474)
Oil, natural gas and NGL gathering, processing and transportation expenses	(1,082)		(1,082)		(1,398)
Severance and ad valorem taxes	(149)		(224)		(189)
Exploration	(427)		(84)		(162)
Depletion and depreciation	(1,026)		(2,188)		(1,665)
Impairment of oil and natural gas properties	(8,446)		(8)		(78)
Imputed income tax provision(a)	1,840		(125)		(326)
Results of operations from oil, natural gas and NGL producing activities	$	(6,266)	$	354	$	926

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

Oil, Natural Gas and NGL Reserve Quantities

Our petroleum engineers and independent petroleum engineering firms estimated all of our proved reserves as of December 31, 2020, 2019 and 2018. Independent petroleum engineering firm LaRoche Petroleum Consultants, Ltd. estimated an aggregate of 87% of our estimated proved reserves (by volume) as of December 31, 2020.

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 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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

SUPPLEMENTARY INFORMATION - (Continued)

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 2020, 2019 and 2018:


	Oil	Natural Gas	NGL	Total
	(mmbbl)	(bcf)	(mmbbl)	(mmboe)
December 31, 2020
Proved reserves, beginning of period	358.0	6,566	120.0	1,572
Extensions, discoveries and other additions	1.1	100	0.4	18
Revisions of previous estimates	(148.2)	(2,326)	(50.6)	(586)
Production	(37.3)	(684)	(11.3)	(163)
Sale of reserves-in-place	(12.3)	(126)	(6.5)	(39)
Purchase of reserves-in-place	—	—	—	—
Proved reserves, end of period	161.3	3,530	52.0	802
Proved developed reserves:
Beginning of period	201.4	3,377	82.1	846
End of period	158.1	3,196	51.4	742
Proved undeveloped reserves:
Beginning of period	156.6	3,189	37.9	726
End of period(a)	3.2	334	0.6	60

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

SUPPLEMENTARY INFORMATION - (Continued)


	Oil	Natural Gas	NGL	Total
	(mmbbl)	(bcf)	(mmbbl)	(mmboe)
December 31, 2019
Proved reserves, beginning of period	215.5	6,777	103.3	1,448
Extensions, discoveries and other additions	52.2	897	13.9	216
Revisions of previous estimates	(40.9)	(516)	(15.8)	(143)
Production	(43.0)	(728)	(12.3)	(177)
Sale of reserves-in-place	(1.8)	(23)	(1.4)	(7)
Purchase of reserves-in-place	176.0	159	32.3	235
Proved reserves, end of period	358.0	6,566	120.0	1,572
Proved developed reserves:
Beginning of period	127.6	3,314	67.9	748
End of period	201.4	3,377	82.1	846
Proved undeveloped reserves:
Beginning of period	87.9	3,463	35.4	700
End of period(a)	156.6	3,189	37.9	726

December 31, 2018
Proved reserves, beginning of period	260.2	8,600	218.6	1,912
Extensions, discoveries and other additions	56.3	1,162	19.8	270
Revisions of previous estimates	(30.5)	242	5.4	15
Production	(32.7)	(832)	(18.9)	(190)
Sale of reserves-in-place	(37.8)	(2,395)	(121.6)	(559)
Purchase of reserves-in-place	—	—	—	—
Proved reserves, end of period	215.5	6,777	103.3	1,448
Proved developed reserves:
Beginning of period	150.9	4,980	135.0	1,116
End of period	127.6	3,314	67.9	748
Proved undeveloped reserves:
Beginning of period	109.3	3,620	83.6	796
End of period(a)	87.9	3,463	35.4	700

(a) As of December 31, 2020, 2019 and 2018, there were no PUDs that had remained undeveloped for five years or more.

During 2020, we recorded extension and discoveries of 18 mmboe primarily in the Marcellus and Gulf Coast primarily related to successfully drilled new well additions. We sold 39 mmboe of proved reserves for approximately $136 million primarily in the Mid-Continent. We recorded 586 mmboe of downward revisions of previous estimates consisting of 423 mmboe of downward revisions due to updates to our five-year development plan in contemplation of ongoing market conditions and uncertainty regarding our ability to finance the development of our proved reserves over a five-year period, downward revisions of 208 mmboe due to lower oil, natural gas and NGL prices in 2020, and upward revisions of 45 mmboe due to ongoing portfolio evaluation including performance adjustments. The oil and natural gas prices used in computing our reserves as of December 31, 2020, were $39.57 per bbl and $1.98 per mcf, respectively, before price differentials.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

SUPPLEMENTARY INFORMATION - (Continued)

During 2019, we acquired 235 mmboe primarily related to the acquisition of WildHorse. We recorded extensions and discoveries of 216 mmboe, primarily related to undeveloped well additions in the Marcellus and Brazos Valley operating areas. In addition, we recorded downward revisions of 110 mmboe due to lower oil, natural gas and NGL prices in 2019, and downward revisions of 33 mmboe due to ongoing portfolio evaluation including lateral length adjustments, performance and updates to our five-year development plan. The oil and natural gas prices used in computing our reserves as of December 31, 2019, were $55.69 per bbl and $2.58 per mcf, respectively, before price differentials.

During 2018, we sold 559 mmboe of proved reserves for approximately $1.8 billion primarily in the Utica and Mid-Continent. We recorded extensions and discoveries of 270 mmboe, primarily related to undeveloped well additions located in Marcellus and Powder River Basin operating areas. In addition, we recorded upward revisions of 28 mmboe due to higher oil, natural gas and NGL prices in 2018 partially offset by downward revisions of 13 mmboe due to ongoing portfolio evaluation including longer lateral and spacing adjustments. The oil and natural gas prices used in computing our reserves as of December 31, 2018, were $65.56 per bbl and $3.10 per mcf, respectively, before price differentials.

Standardized Measure of Discounted Future Net Cash Flows

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

Future cash inflows and future production and development costs as of December 31, 2020, 2019 and 2018 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.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

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,
	2020			2019			2018
	($ in millions)
Future cash inflows	$	8,247	(a)	$	29,857	(b)	$	27,312	(c)
Future production costs	(2,963)			(6,956)			(5,946)
Future development costs	(563)			(5,757)			(4,032)
Future income tax provisions	(9)			(75)			(331)
Future net cash flows	4,712			17,069			17,003
Less effect of a 10% discount factor	(1,626)			(8,069)			(7,508)
Standardized measure of discounted future net cash flows(d)	$	3,086		$	9,000		$	9,495

(a) Calculated using prices of $39.57 per bbl of oil and $1.98 per mcf of natural gas, before field differentials.

(b) Calculated using prices of $55.69 per bbl of oil and $2.58 per mcf of natural gas, before field differentials.

(d) Excludes discounted future net cash inflows attributable to production volumes sold to VPP buyers. See Note 7.

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


	Years Ended December 31,
	2020		2019		2018
	($ in millions)
Standardized measure, beginning of period(a)	$	9,000	$	9,495	$	7,490
Sales of oil and natural gas produced, net of production costs and gathering, processing and transportation(b)	(1,140)		(2,691)		(3,128)
Net changes in prices and production costs	(5,576)		(3,457)		3,317
Extensions and discoveries, net of production and development costs	71		991		1,666
Changes in estimated future development costs	1,933		366		1,113
Previously estimated development costs incurred during the period	665		775		973
Revisions of previous quantity estimates	(1,839)		(793)		47
Purchase of reserves-in-place	—		3,435		—
Sales of reserves-in-place	(112)		(57)		(2,052)
Accretion of discount	902		953		749
Net change in income taxes	14		17		(32)
Changes in production rates and other	(832)		(34)		(648)
Standardized measure, end of period(a)	$	3,086	$	9,000	$	9,495

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

(b) Excludes gains and losses on derivatives.

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