PART I. FINANCIAL INFORMATION


ITEM 1.			Condensed Consolidated Financial Statements ~~(Unaudited)~~

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~(Unaudited)~~

September 30,
2017 December 31,
2016
($ in millions)
CURRENT ASSETS:
Cash and cash equivalents ($1 and $1 attributable to our VIE) $ 5
$ 882
Accounts receivable, net 992
1,057
Short-term derivative assets 28
—
Other current assets 153
203
Total Current Assets 1,178
2,142
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting:
Proved oil and natural gas properties
($488 and $488 attributable to our VIE)
68,095
66,451
Unproved properties 3,838
4,802
Other property and equipment 2,004
2,053
Total Property and Equipment, at Cost 73,937
73,306
Less: accumulated depreciation, depletion and amortization
(($460) and ($458) attributable to our VIE)
(63,375 ) (62,726 )
Property and equipment held for sale, net 18
29
Total Property and Equipment, Net 10,580
10,609
LONG-TERM ASSETS:
Other long-term assets 223
277
TOTAL ASSETS $ 11,981
$ 13,028

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS ~~– (Continued)~~(Unaudited)

~~(Unaudited)~~


($ in millions, except per share data)	March 31, 2023		December 31, 2022
Assets
Current assets:
Cash and cash equivalents	$	130	$	130
Restricted cash	67		62
Accounts receivable, net	864		1,438
Short-term derivative assets	464		34
Assets held for sale	862		819
Other current assets	242		215
Total current assets	2,629		2,698
Property and equipment:
Natural gas and oil properties, successful efforts method
Proved natural gas and oil properties	10,793		11,096
Unproved properties	2,002		2,022
Other property and equipment	498		500
Total property and equipment	13,293		13,618
Less: accumulated depreciation, depletion and amortization	(2,770)		(2,431)

Total property and equipment, net	10,523		11,187
Long-term derivative assets	122		47
Deferred income tax assets	973		1,351
Other long-term assets	344		185
Total assets	$	14,591	$	15,468

Liabilities and stockholders' equity
Current liabilities:
Accounts payable	$	631	$	603
Accrued interest	40		42
Short-term derivative liabilities	25		432
Other current liabilities	1,202		1,627
Total current liabilities	1,898		2,704
Long-term debt, net	2,040		3,093
Long-term derivative liabilities	42		174
Asset retirement obligations, net of current portion	279		323
Other long-term liabilities	49		50
Total liabilities	4,308		6,344
Contingencies and commitments (Note 5)
Stockholders' equity:
Common stock, $0.01 par value, 450,000,000 shares authorized: 134,019,253 and 134,715,094 shares issued	1		1
Additional paid-in capital	5,729		5,724
Retained earnings	4,553		3,399
Total stockholders' equity	10,283		9,124
Total liabilities and stockholders' equity	$	14,591	$	15,468

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

September 30,
2017 December 31,
2016
($ in millions)
CURRENT LIABILITIES:
Accounts payable $ 678
$ 672
Current maturities of long-term debt, net —
503
Accrued interest 135
113
Short-term derivative liabilities 8
562
Other current liabilities ($4 and $3 attributable to our VIE) 1,397
1,798
Total Current Liabilities 2,218
3,648
LONG-TERM LIABILITIES:
Long-term debt, net 9,899
9,938
Long-term derivative liabilities 11
15
Asset retirement obligations, net of current portion 197
247
Other long-term liabilities 360
383
Total Long-Term Liabilities 10,467
10,583
CONTINGENCIES AND COMMITMENTS (Note 4)

EQUITY:
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized:
5,603,458 and 5,839,506 shares outstanding 1,671
1,771
Common stock, $0.01 par value,
2,000,000,000 and 1,500,000,000 shares authorized:
908,662,243 and 896,279,353 shares issued
9
9
Additional paid-in capital 14,449
14,486
Accumulated deficit (16,987 ) (17,603 )
Accumulated other comprehensive loss (67 ) (96 )
Less: treasury stock, at cost;
2,323,475 and 1,220,504 common shares
(32 ) (27 )
Total Chesapeake Stockholders’ Equity (Deficit) (957 ) (1,460 )
Noncontrolling interests 253
257
Total Equity (Deficit) (704 ) (1,203 )
TOTAL LIABILITIES AND EQUITY $ 11,981
$ 13,028

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


($ in millions, except per share data)	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022
Revenues and other:
Natural gas, oil and NGL	$	1,453	$	1,914
Marketing	652		867
Natural gas and oil derivatives	930		(2,125)
Gains on sales of assets	335		279
Total revenues and other	3,370		935
Operating expenses:
Production	131		110
Gathering, processing and transportation	264		242
Severance and ad valorem taxes	69		63
Exploration	7		5
Marketing	651		851
General and administrative	35		26

Depreciation, depletion and amortization	390		409

Other operating expense, net	3		23
Total operating expenses	1,550		1,729
Income (loss) from operations	1,820		(794)
Other income (expense):
Interest expense	(37)		(32)

Other income	10		16
Total other income (expense)	(27)		(16)
Income (loss) before income taxes	1,793		(810)
Income tax expense (benefit)	404		(46)


Net income (loss) available to common stockholders	$	1,389	$	(764)
Earnings (loss) per common share:
Basic	$	10.31	$	(6.32)
Diluted	$	9.60	$	(6.32)
Weighted average common shares outstanding (in thousands):
Basic	134,742		120,805
Diluted	144,731		120,805

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
($ in millions except per share data)
REVENUES:
Oil, natural gas and NGL $ 979
$ 1,177
$ 3,727
$ 2,610
Marketing, gathering and compression 964
1,099
3,250
3,241
Total Revenues 1,943
2,276
6,977
5,851
OPERATING EXPENSES:
Oil, natural gas and NGL production 151
164
426
552
Oil, natural gas and NGL gathering, processing and transportation 369
473
1,081
1,436
Production taxes 21
17
64
54
Marketing, gathering and compression 978
1,261
3,333
3,410
General and administrative 54
63
189
172
Restructuring and other termination costs —
—
—
3
Provision for legal contingencies 20
8
35
112
Oil, natural gas and NGL depreciation, depletion and amortization 228
251
627
791
Depreciation and amortization of other assets 20
25
62
83
Impairment of oil and natural gas properties —
497
—
2,564
Impairments of fixed assets and other 9
751
426
795
Net gains on sales of fixed assets (1 ) —
—
(5 )
Total Operating Expenses 1,849
3,510
6,243
9,967
INCOME (LOSS) FROM OPERATIONS 94
(1,234 ) 734
(4,116 )
OTHER INCOME (EXPENSE):
Interest expense (114 ) (73 ) (302 ) (197 )
Losses on investments —
(1 ) —
(3 )
Loss on sale of investment —
—
—
(10 )
Gains (losses) on purchases or exchanges of debt (1 ) 87
183
255
Other income 4
7
6
13
Total Other Income (Expense) (111 ) 20
(113 ) 58
INCOME (LOSS) BEFORE INCOME TAXES (17 ) (1,214 ) 621
(4,058 )
Income Tax Expense —
—
2
—
NET INCOME (LOSS) (17 ) (1,214 ) 619
(4,058 )
Net income attributable to noncontrolling interests (1 ) (1 ) (3 ) (1 )
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE (18 ) (1,215 ) 616
(4,059 )
Preferred stock dividends (23 ) (42 ) (62 ) (127 )
Loss on exchange of preferred stock —
—
(41 ) —
Earnings allocated to participating securities —
—
(7 ) —
NET INCOME (LOSS) AVAILABLE TO
COMMON STOCKHOLDERS
$ (41 ) $ (1,257 ) $ 506
$ (4,186 )
EARNINGS (LOSS) PER COMMON SHARE:
Basic $ (0.05 ) $ (1.62 ) $ 0.56
$ (5.80 )
Diluted $ (0.05 ) $ (1.62 ) $ 0.56
$ (5.80 )
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
Basic 909
777
908
722
Diluted 909
777
908
722

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)~~

~~(Unaudited)~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
($ in millions)
NET INCOME (LOSS) $ (17 ) $ (1,214 ) $ 619
$ (4,058 )
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:
Unrealized gains (losses) on derivative instruments,
net of income tax expense (benefit)
of $0, $0, $0 and ($1)
—
(4 ) 4
(23 )
Reclassification of losses on settled derivative instruments, net of income tax expense (benefit)
of $0, $0, $0 and $3
8
7
25
21
Other Comprehensive Income (Loss) 8
3
29
(2 )
COMPREHENSIVE INCOME (LOSS) (9 ) (1,211 ) 648
(4,060 )
COMPREHENSIVE INCOME ATTRIBUTABLE TO
NONCONTROLLING INTERESTS
(1 ) (1 ) (3 ) (1 )
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE $ (10 ) $ (1,212 ) $ 645
$ (4,061 )

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


($ in millions)	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022
Cash flows from operating activities:
Net income (loss)	$	1,389	$	(764)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	390		409
Deferred income tax expense	378		—
Derivative (gains) losses, net	(930)		2,125
Cash payments on derivative settlements, net	(285)		(568)
Share-based compensation	7		4
Gains on sales of assets	(335)		(279)

Exploration	3		4

Other	9		(8)
Changes in assets and liabilities	263		(70)
Net cash provided by operating activities	889		853
Cash flows from investing activities:
Capital expenditures	(497)		(344)
Business combination, net	—		(2,006)
Contributions to investments	(39)		—
Proceeds from divestitures of property and equipment	931		403
Net cash provided by (used in) investing activities	395		(1,947)
Cash flows from financing activities:
Proceeds from New Credit Facility	1,000		—
Payments on New Credit Facility	(2,050)		—
Proceeds from Exit Credit Facility	—		1,565
Payments on Exit Credit Facility	—		(1,065)

Proceeds from warrant exercise	—		1

Cash paid to repurchase and retire common stock	(54)		(83)

Cash paid for common stock dividends	(175)		(210)
Net cash provided by (used in) financing activities	(1,279)		208
Net increase (decrease) in cash, cash equivalents and restricted cash	5		(886)
Cash, cash equivalents and restricted cash, beginning of period	192		914
Cash, cash equivalents and restricted cash, end of period	$	197	$	28

Cash and cash equivalents	$	130	$	19
Restricted cash	67		9
Total cash, cash equivalents and restricted cash	$	197	$	28

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

Nine Months Ended
September 30,
2017 2016
($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS) $ 619
$ (4,058 )
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH
PROVIDED BY (USED IN) OPERATING ACTIVITIES:

Depreciation, depletion and amortization 689
874
Derivative (gains) losses, net (452 ) 283
Cash receipts (payments) on derivative settlements, net (46 ) 487
Stock-based compensation 38
40
Impairment of oil and natural gas properties —
2,564
Net gains on sales of fixed assets —
(5 )
Renegotiation of natural gas gathering contract —
(66 )
Impairments of fixed assets and other 9
785
Losses on investments —
3
Loss on sale of investment —
10
Gains on purchases or exchanges of debt (185 ) (255 )
Restructuring and other termination costs —
1
Provision for legal contingencies 35
77
Other (68 ) (76 )
Changes in assets and liabilities (366 ) (614 )
Net Cash Provided By Operating Activities 273
50
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs (1,597 ) (948 )
Acquisitions of proved and unproved properties (226 ) (583 )
Proceeds from divestitures of proved and unproved properties 1,193
988
Additions to other property and equipment (12 ) (32 )
Proceeds from sales of other property and equipment 40
70
Cash paid for title defects —
(69 )
Other —
(5 )
Net Cash Used In Investing Activities (602 ) (579 )

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)

(Unaudited)

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


($ in millions)	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022
Supplemental cash flow information:

Interest paid, net of capitalized interest	$	41	$	31
Income taxes paid, net of refunds received	$	—	$	(5)

Supplemental disclosure of significant non-cash investing and financing activities:
Change in accrued drilling and completion costs	$	56	$	6

Common stock issued for business combination	$	—	$	764
Operating lease obligations recognized	$	48	$	—

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

Nine Months Ended
September 30,
2017 2016
($ in millions)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings 4,775
5,097
Payments on revolving credit facility borrowings (4,130 ) (4,857 )
Proceeds from issuance of senior notes, net 742
—
Proceeds from issuance of term loan —
1,500
Cash paid to purchase debt (1,751 ) (1,979 )
Cash paid for preferred stock dividends (160 ) —
Distributions to noncontrolling interest owners (7 ) (8 )
Other (17 ) (45 )
Net Cash Used In Financing Activities (548 ) (292 )
Net decrease in cash and cash equivalents (877 ) (821 )
Cash and cash equivalents, beginning of period 882
825
Cash and cash equivalents, end of period $ 5
$ 4

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

Nine Months Ended
September 30,
2017 2016
($ in millions)
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest $ 342
$ 209
Income tax refunds received, net $ (15 ) $ (20 )

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in accrued drilling and completion costs $ 134
$ (22 )
Change in accrued acquisitions of proved and unproved properties $ (1 ) $ (1 )
Change in divested proved and unproved properties $ (23 ) $ 12
Debt exchanged for common stock $ —
$ 471

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)


	Common Stock
($ in millions)	Shares	Amount		Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Total Stockholders' Equity
Balance as of December 31, 2022	134,715,094	$	1	$	5,724	$	3,399	$	9,124
Share-based compensation	92,048	—		5		—		5
Issuance of common stock for warrant exercise	4,654	—		—		—		—
Repurchase and retirement of common stock	(792,543)	—		—		(60)		(60)
Net income	—	—		—		1,389		1,389
Dividends on common stock	—	—		—		(175)		(175)
Balance as of March 31, 2023	134,019,253	$	1	$	5,729	$	4,553	$	10,283

Balance as of December 31, 2021	117,917,349	$	1	$	4,845	$	825	$	5,671
Issuance of common stock for Marcellus Acquisition	9,442,185	—		764		—		764
Share-based compensation	23,169	—		5		—		5
Issuance of common stock for warrant exercise	669,669	—		1		—		1
Repurchase and retirement of common stock	(1,000,000)	—		—		(83)		(83)
Net loss	—	—		—		(764)		(764)
Dividends on common stock	—	—		—		(211)		(211)
Balance as of March 31, 2022	127,052,372	$	1	$	5,615	$	(233)	$	5,383

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

Nine Months Ended
September 30,
2017 2016
($ in millions)
PREFERRED STOCK:
Balance, beginning of period $ 1,771
$ 3,062
Exchange/conversions of 236,048 and 25,802 shares of preferred stock for common stock (100 ) (26 )
Balance, end of period 1,671
3,036
COMMON STOCK:
Balance, beginning of period 9
7
Exchange of senior notes, contingent convertible notes and preferred stock —
1
Balance, end of period 9
8
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period 14,486
12,403
Stock-based compensation 43
49
Exchange of contingent convertible notes for 0 and 55,427,782 shares of common stock —
241
Exchange of senior notes for 0 and 53,923,925 shares of common stock —
229
Exchange/conversion of preferred stock for 9,965,835 and 1,021,506
shares of common stock
100
26
Equity component of contingent convertible notes repurchased (20 ) (25 )
Dividends on preferred stock (160 ) —
Balance, end of period 14,449
12,923
ACCUMULATED DEFICIT:
Balance, beginning of period (17,603 ) (13,202 )
Net income (loss) attributable to Chesapeake 616
(4,059 )
Balance, end of period (16,987 ) (17,261 )
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period (96 ) (99 )
Hedging activity 29
(2 )
Balance, end of period (67 ) (101 )
TREASURY STOCK – COMMON:
Balance, beginning of period (27 ) (33 )
Purchase of 1,194,986 and 33,955 shares for company benefit plans (7 ) —
Release of 92,015 and 182,092 shares from company benefit plans 2
4
Balance, end of period (32 ) (29 )
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT) (957 ) (1,424 )
NONCONTROLLING INTERESTS:
Balance, beginning of period 257
259
Net income attributable to noncontrolling interests 3
1
Distributions to noncontrolling interest owners (7 ) (1 )
Balance, end of period 253
259
TOTAL EQUITY (DEFICIT) $ (704 ) $ (1,165 )

Table of these errors was reflected in the quarterly unaudited financial data included within our 2016 Form 10-K. These revisions have been reflected in the comparative 2016 condensed consolidated financial statements presented herein. See ~~Evaluation of Disclosure Controls and Procedures in Item 4 of this Form 10-Q. The following table reconciles the amounts as previously reported in the applicable financial statement to the corresponding revised amounts:~~

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


1.			Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

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

Basis of Presentation

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

This Quarterly Report on Form 10-Q (this “Form 10-Q”) relates to our financial position as of March 31, 2023 and December 31, 2022, and our results of operations for the three months ended March 31, 2023 and March 31, 2022. Our annual report on Form 10-K for the year ended December 31, 2022 (“2022 Form 10-K”) should be read in conjunction with this Form 10-Q. The accompanying unaudited condensed consolidated financial statements reflect all normal recurring adjustments that, in the ~~United States (U.S. GAAP)~~opinion of management, are necessary for a fair statement of our condensed consolidated financial statements and accompanying notes and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which ~~Chesapeake has~~we have a controlling financial interest. Intercompany accounts and balances have been eliminated. ~~These financial statements were prepared in accordance with~~For the ~~instructions to~~time periods covered by this Form 10-Q, we did not have any changes or items impacting other comprehensive income.

Segments

Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and ~~therefore, do not include all disclosures required~~incur expenses for which separate operational financial ~~statements prepared in conformity with U.S. GAAP.~~

~~This Form 10-Q relates~~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 due to the ~~three~~similar nature of the exploration and ~~nine months ended September 30, 2017 (the “Current Quarter”~~production business across Chesapeake and its consolidated subsidiaries and the “Current Period”, respectively) and the three and nine months ended September 30, 2016 (the “Prior Quarter” and the “Prior Period”, respectively). Chesapeake’s annual report on Form 10-Kfact that our marketing activities are ancillary to our operations.

Restricted Cash

As of March 31, 2023, we had restricted cash of $67 million. Our restricted cash represents funds legally restricted for ~~the year ended December 31, 2016 (“2016 Form 10-K”) includes~~payment of certain ~~definitions and a summary~~convenience class unsecured claims following our emergence from bankruptcy, as well as for future payment of significant accounting policies and should be read in conjunction with this Form 10-Q. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessarycertain royalties.

Assets Held for a fair statement of the results for the interim periods have been reflected. The results for the Current Quarter and the Current Period are not necessarily indicative of the results to be expected for the full year.Sale

~~Revision of Previously Reported Condensed Consolidated Financial Statements~~

~~During the fourth quarter of 2016, we identified~~We may market certain ~~errors to the basis price differentials used in calculating the impairment of oil and natural gas properties and oil,~~non-core natural gas and ~~NGL depreciation, depletion~~oil assets or other properties for sale. At the end of each reporting period, we evaluate if these assets should be classified as held for sale. The held for sale criteria includes the following: management commits to a plan to sell, the asset is available for immediate sale, an active program to locate a buyer exists, the sale of the asset is probable and ~~amortization~~expected to be completed within a year, the asset is actively being marketed for sale and that it is unlikely that significant changes to the plan will be made. If each of the ~~first three interim periods~~criteria are met, then the assets and associated liabilities are classified as held for sale. As of March 31, 2023, the asset and liabilities held for sale are in ~~2016. As disclosed within~~connection with a portion of our ~~2016 Form 10-K, it was determined that these errors were not material~~remaining Eagle Ford assets for which we had entered into an agreement to ~~our previously issued 2016 interim financial statements. Accordingly, the correction~~sell to INEOS Energy. This transaction closed on April 28, 2023. See Note 2 for further discussion.

Three Months Ended September 30, 2016
CONDENSED CONSOLIDATED STATEMENTS
OF OPERATIONS
As Previously
Reported
Revision
Adjustment

As
Revised
($ in millions except per share data)
Oil, natural gas and NGL depreciation, depletion and amortization $ 255
$ (4 ) $ 251
Impairment of oil and natural gas properties $ 433
$ 64
$ 497
Total operating expenses $ 3,450
$ 60
$ 3,510
Loss from operations $ (1,174 ) $ (60 ) $ (1,234 )
Loss before income taxes $ (1,154 ) $ (60 ) $ (1,214 )
Net loss $ (1,154 ) $ (60 ) $ (1,214 )
Net loss attributable to Chesapeake $ (1,155 ) $ (60 ) $ (1,215 )
Net loss available to common stockholders $ (1,197 ) $ (60 ) $ (1,257 )
Loss per common share basic $ (1.54 ) $ (0.08 ) $ (1.62 )
Loss per common share diluted $ (1.54 ) $ (0.08 ) $ (1.62 )

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)


2.			Natural Gas and Oil Property Transactions

Marcellus Acquisition

On March 9, 2022, we closed the Marcellus Acquisition for total consideration of approximately $2.77 billion, consisting of approximately $2 billion in cash, including working capital adjustments and approximately 9.4 million shares of our common stock, to acquire high quality producing assets and a deep inventory of premium drilling locations in the prolific Marcellus Shale in Northeast Pennsylvania. The Marcellus Acquisition was indebtedness free, effective as of January 1, 2022, and was subject to customary purchase price adjustments. We funded the cash portion of the consideration with cash on hand and $914 million of borrowings under the Company’s Exit Credit Facility. During the first three months of 2022, we recognized approximately $23 million of costs related to our Marcellus Acquisition, which included consulting fees, financial advisory fees, legal fees and change in control expense in accordance with Chief’s existing employment agreements. These acquisition-related costs are included within other operating expense, net within our condensed consolidated statements of operations.

Marcellus Acquisition Purchase Price Allocation

We have accounted for the Marcellus Acquisition as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. We finalized the acquisition accounting for this transaction during 2022.


	Purchase Price Allocation
Consideration:
Cash	$	2,000
Fair value of Chesapeake’s common stock issued in the merger (a)	764
Working capital adjustments	6
Total consideration	$	2,770

Fair Value of Liabilities Assumed:
Current liabilities	$	459
Other long-term liabilities	129
Amounts attributable to liabilities assumed	$	588

Fair Value of Assets Acquired:
Cash, cash equivalents and restricted cash	$	39
Other current assets	218
Proved natural gas and oil properties	2,309
Unproved properties	788
Other property and equipment	1
Other long-term assets	3
Amounts attributable to assets acquired	$	3,358

Total identifiable net assets	$	2,770

(a)The fair value of our common stock is a Level 1 input, as our stock price is a quoted price in an active market as of the acquisition date.

Nine Months Ended September 30, 2016
CONDENSED CONSOLIDATED STATEMENTS
OF OPERATIONS
As Previously
Reported

Revision
Adjustment

As
Revised
($ in millions except per share data)
Impairment of oil and natural gas properties $ 2,331
$ 233
$ 2,564
Total operating expenses $ 9,734
$ 233
$ 9,967
Loss from operations $ (3,883 ) $ (233 ) $ (4,116 )
Loss before income taxes $ (3,825 ) $ (233 ) $ (4,058 )
Net loss $ (3,825 ) $ (233 ) $ (4,058 )
Net loss attributable to Chesapeake $ (3,826 ) $ (233 ) $ (4,059 )
Net loss available to common stockholders $ (3,953 ) $ (233 ) $ (4,186 )
Loss per common share basic $ (5.47 ) $ (0.33 ) $ (5.80 )
Loss per common share diluted $ (5.47 ) $ (0.33 ) $ (5.80 )

Three Months Ended September 30, 2016
CONDENSED CONSOLIDATED STATEMENTS
OF COMPREHENSIVE INCOME (LOSS)

As Previously
Reported

Revision
Adjustment

As
Revised
($ in millions)
Net loss $ (1,154 ) $ (60 ) $ (1,214 )
Comprehensive loss $ (1,151 ) $ (60 ) $ (1,211 )
Comprehensive loss attributable to Chesapeake $ (1,152 ) $ (60 ) $ (1,212 )

Nine Months Ended September 30, 2016
CONDENSED CONSOLIDATED STATEMENTS
OF COMPREHENSIVE INCOME (LOSS) As Previously
Reported Revision
Adjustment As
Revised
($ in millions)
Net loss $ (3,825 ) $ (233 ) $ (4,058 )
Comprehensive loss $ (3,827 ) $ (233 ) $ (4,060 )
Comprehensive loss attributable to Chesapeake $ (3,828 ) $ (233 ) $ (4,061 )

Nine Months Ended September 30, 2016
CONDENSED CONSOLIDATED STATEMENTS
OF CASH FLOWS As Previously
Reported Revision
Adjustment As
Revised
($ in millions)
Net loss $ (3,825 ) $ (233 ) $ (4,058 )
Impairment of oil and natural gas properties $ 2,331
$ 233
$ 2,564

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)

Natural Gas and Oil Properties

For the Marcellus Acquisition, 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 natural gas and oil properties as of the acquisition date was based on estimated natural gas and oil 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 NYMEX strip pricing adjusted for inflation to value the reserves. 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 natural gas and oil properties acquired. Additionally, the fair value estimate of proved and unproved natural gas and oil properties was corroborated by utilizing a market approach, which considers recent comparable transactions for similar assets.

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

Marcellus Acquisition Revenues and Expenses Subsequent to Acquisition

For the period from March 10, 2022 to March 31, 2022, we included in our condensed consolidated statements of operations natural gas, oil and NGL revenues of $59 million, net losses on natural gas and oil derivatives of $200 million, and direct operating expenses of $30 million, including depreciation, depletion and amortization related to the Marcellus Acquisition businesses.

Pro Forma Financial Information

As the Marcellus Acquisition closed on March 9, 2022, all activity in 2023 is included in Chesapeake’s condensed consolidated statements of operations for the first three months of 2023. The following unaudited pro forma financial information is based on our historical consolidated financial statements adjusted to reflect as if the Marcellus Acquisition occurred on January 1, 2022. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including the estimated tax impact of the pro forma adjustments.


2.	~~Earnings Per Share~~	Three Months Ended March 31, 2022
Revenues		$	935
Net loss available to common stockholders		$	(868)
Loss per common share:
Basic		$	(6.83)
Diluted		$	(6.83)

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

Eagle Ford Divestitures

In January 2023, we entered into an agreement to ~~our employees and non-employee directors that provide dividend rights.~~

Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For all periods presented, our contingent convertible senior notes did not havesell a ~~dilutive effect and therefore were excluded from the calculation of diluted EPS. See Note 3 for further discussion~~portion of our ~~convertible senior notes~~Eagle Ford assets to WildFire Energy I LLC for approximately $1.425 billion, subject to customary closing adjustments. Approximately $225 million of the purchase price was recorded as deferred consideration and ~~contingent convertible senior notes.~~

~~Shares~~treated as a non-interest-bearing note to be paid in installments of ~~common stock~~$60 million per year for the next three years, with $45 million to be paid in the fourth year following ~~dilutive securities~~the transaction close date. The deferred consideration is recorded at fair value with an imputed rate of interest as a Level 2 input, and approximately $55 million of the deferred consideration is reflected within other current assets and $125 million is reflected within other long-term assets on the condensed consolidated balance sheets as of March 31, 2023. The divestiture, which closed on March 20, 2023, resulted in a gain of approximately $335 million based on the difference between the carrying value of the assets and consideration received. As of December 31, 2022, approximately $811 million of property and equipment, net and $8 million of other assets were ~~excluded from~~classified as assets held for sale on the ~~calculation~~condensed consolidated balance sheets. Additionally, approximately $65 million of ~~diluted EPS~~derivative liabilities, $57 million of asset retirement obligations and $22 million of other liabilities were classified as held for sale and included within other current liabilities on the ~~effect was antidilutive.~~condensed consolidated balance sheets as of December 31, 2022.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(in millions)
Common stock equivalent of our preferred stock outstanding 60
112
60
112
Common stock equivalent of our convertible senior notes outstanding 146
—
146
—
Participating securities —
1
1
1

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)

In February 2023, we entered into an agreement to sell a portion of our remaining Eagle Ford assets to INEOS Energy for approximately $1.4 billion, subject to customary closing adjustments. This transaction closed on April 28, 2023 and we received proceeds of approximately $1.055 billion. Approximately $225 million of the purchase price was recorded as deferred consideration and treated as a non-interest-bearing note to be paid in installments of approximately $56 million per year for the next four years. In February 2023, we ceased depreciation on the assets associated with the sale. We classified approximately $814 million of property and equipment, net, $22 million of right of use lease assets, and $26 million of other assets as held for sale included within current assets held for sale on the condensed consolidated balance sheets as of March 31, 2023. Additionally, approximately $53 million of asset retirement obligations liabilities, $22 million of lease liabilities and $16 million of other liabilities were classified as held for sale and included within other current liabilities on the condensed consolidated balance sheets as of March 31, 2023.

Powder River Divestiture

In January 2022, Chesapeake signed an agreement to sell its Powder River Basin assets in Wyoming to Continental Resources, Inc. for approximately $450 million, subject to customary closing adjustments. The divestiture, which closed on March 25, 2022, resulted in the recognition of a gain of approximately $293 million, which included $13 million of post-close adjustments, based on the difference between the carrying value of the assets and the cash received.


3.			~~Debt~~Earnings Per Share

~~Our long-term debt consisted~~Basic earnings (loss) per common share is computed by dividing the net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding during the ~~following~~period. Diluted earnings (loss) per common share is calculated in the same manner but includes the impact of potentially dilutive securities. Potentially dilutive securities consists of issuable shares related to warrants, unvested restricted stock units (“RSUs”), and unvested performance share units (“PSUs”).

The reconciliations between basic and diluted earnings (loss) per share are as follows:


	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022
Numerator
Net income (loss) available to common stockholders, basic and diluted	$	1,389	$	(764)

Denominator (in thousands)
Weighted average common shares outstanding, basic	134,742		120,805
Effect of potentially dilutive securities
Warrants	9,560		—
Restricted stock units	380		—
Performance share units	49		—
Weighted average common shares outstanding, diluted	144,731		120,805

Earnings (loss) per common share:
Basic	$	10.31	$	(6.32)
Diluted	$	9.60	$	(6.32)

During the first three months of ~~September 30, 2017~~2023, the diluted earnings per share calculation excludes the effect of 789,458 reserved shares of common stock and ~~December 31, 2016:~~1,489,337 reserved Class C Warrants related to the settlement of General Unsecured Claims associated with the Chapter 11 Cases, as all necessary conditions had not been met for such shares to be considered dilutive shares.

September 30, 2017 December 31, 2016

Principal
Amount
Carrying
Amount Principal
Amount Carrying
Amount
($ in millions)
Term loan due 2021 $ 1,500
$ 1,500
$ 1,500
$ 1,500
6.25% euro-denominated senior notes
due 2017^(a)
—
—
258
258
6.5% senior notes due 2017 —
—
134
134
7.25% senior notes due 2018 44
44
64
64
Floating rate senior notes due 2019 380
380
380
380
6.625% senior notes due 2020 572
572
780
780
6.875% senior notes due 2020 279
278
279
278
6.125% senior notes due 2021 550
550
550
550
5.375% senior notes due 2021 270
270
270
270
4.875% senior notes due 2022 451
451
451
451
8.00% senior secured second lien notes due 2022^(b)
1,737
2,355
2,419
3,409
5.75% senior notes due 2023 338
338
338
338
8.00% senior notes due 2025 1,000
987
1,000
985
5.5% convertible senior notes due 2026^(c)(d)
1,250
831
1,250
811
8.00% senior notes due 2027 750
750
—
—
2.75% contingent convertible senior notes due 2035 —
—
2
2
2.5% contingent convertible senior notes due 2037^(d)
—
—
114
112
2.25% contingent convertible senior notes due 2038^(d)
9
8
200
180
Revolving credit facility 645
645
—
—
Debt issuance costs —
(62 ) —
(64 )
Interest rate derivatives^(e)
—
2
—
3
Total debt, net 9,775
9,899
9,989
10,441
Less current maturities of long-term debt, net —
—
(506 ) (503 )
Total long-term debt, net^(f)
$ 9,775
$ 9,899
$ 9,483
$ 9,938


~~(a)~~	~~The principal and carrying amounts shown are based on the exchange rate of~~ ~~$1.0517~~ ~~to €1.00 as of December 31, 2016. See~~ ~~Foreign Currency Derivatives~~ ~~in Note 8 for information on our related foreign currency derivatives.~~


~~(b)~~	The carrying amounts as of September 30, 2017 and December 31, 2016, include premium amounts of $618 million and $990 million, respectively, associated with a troubled debt restructuring. The premium is being amortized based on the effective yield method.

Table of approximately $1 million in the Current Quarter and an aggregate gain of approximately $183 million in the Current Period including $260 million of premium associated with our 8.00% Senior Secured Second Lien Notes due 2022.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)

During the first three months of 2022, the diluted loss per share calculation excludes the effect of 1,228,828 reserved shares of common stock and 2,318,446 reserved Class C Warrants related to the settlement of General Unsecured Claims associated with the Chapter 11 Cases, as all necessary conditions had not been met for such shares to be considered dilutive shares. Additionally, as the first three months of 2022 had a net loss, the diluted loss per share calculation excludes the antidilutive effect, calculated using the treasury stock method, of 19,621,344 issuable shares related to warrants, 457,680 shares of restricted stock units, and 47,458 shares related to performance share units.


~~(c)~~4.			~~The conversion and redemption provisions of our convertible senior notes are as follows:~~Debt

~~Optional Conversion by Holders. Prior to maturity~~Our long-term debt consisted of the following as of March 31, 2023 and December 31, 2022:


	March 31, 2023				December 31, 2022
	Carrying Amount		Fair Value(a)		Carrying Amount		Fair Value(a)
New Credit Facility	$	—	$	—	$	1,050	$	1,050
5.50% senior notes due 2026	500		492		500		485
5.875% senior notes due 2029	500		476		500		475
6.75% senior notes due 2029	950		948		950		917
Premiums on senior notes	97		—		100		—
Debt issuance costs	(7)		—		(7)		—
Total long-term debt, net	$	2,040	$	1,916	$	3,093	$	2,927

(a)The carrying value of borrowings under ~~certain circumstances and at~~our New Credit Facility approximate fair value as the ~~holder’s option, the notes~~interest rates are convertible into cash, our common stock, or a combination of cash and common stock, at our election. One triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on ~~common stock price~~prevailing market rates; therefore, they are a Level 1 fair value measurement. For all other debt, a market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is ~~measured quarterly. During~~used to measure the ~~Current Quarter,~~fair value.

New Credit Facility. In December 2022, we entered into a senior secured reserve-based credit agreement (the “New Credit Agreement”) with the ~~price~~lenders and issuing banks party thereto (the “Lenders”), and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (in such capacity, the “Administrative Agent”), providing for a reserve-based credit facility (the “New Credit Facility”) with an initial borrowing base of ~~our common stock was below the threshold level~~$3.5 billion and asaggregate commitments of $2.0 billion. The New Credit Facility matures in December 2027. The New Credit Facility provides for a result, the holders do not have the option to convert their notes in the fourth quarter of 2017 under this provision. The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision during the Current Quarter. Upon conversion of a convertible senior note, the holder will receive cash, common stock or a combination of cash and common stock, at our election, according to the conversion rate specified in the indenture.

~~The common stock price conversion threshold amount~~$200 million sublimit available for the ~~convertible senior notes~~issuance of letters of credit and a $50 million sublimit available for swingline loans.

Initially, the obligations under the New Credit Facility are guaranteed by certain of Chesapeake’s subsidiaries (the “Guarantors”), and the New Credit Facility is ~~130% of the conversion price of $8.568.~~

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

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


~~(d)~~	The carrying amounts as of September 30, 2017 and December 31, 2016, are reflected net of discounts of $420 million and $461 million, respectively, associated with the equity component of our convertible and contingent convertible senior notes. This amount is being amortized based on the effective yield method through the first demand repurchase date as applicable.


~~(e)~~	~~See~~ ~~Interest Rate Derivatives~~ ~~in Note 8 for further discussion related to these instruments.~~


~~(f)~~	~~See Note 16 for information regarding debt transactions subsequent to September 30, 2017.~~

~~Debt Issuances and Retirements~~

During the Current Period, we issued in a private placement $750 million aggregate principal amount of unsecured 8.00% Senior Notes due 2027 at par for net proceeds of approximately $742 million. Some orsubstantially all of the ~~notes may~~assets owned by the Company and the Guarantors (subject to customary exceptions), including mortgages on not less than 85% of the total PV-9 of the borrowing base properties evaluated in the most recent reserve report (where PV-9 is the net present value, discounted at 9% per annum, of the estimated future net revenues). The borrowing base will be ~~redeemed~~redetermined semi-annually in or around April and October of each year, with one interim “wildcard” redetermination available to each of the Company and the Administrative Agent, the latter at ~~any time prior~~the direction of the Required Lenders (as defined in the New Credit Agreement), between scheduled redeterminations. Our borrowing base was reaffirmed in April 2023, and the next scheduled redetermination will be in or around October 2023. The New Credit Agreement contains restrictive covenants that limit Chesapeake and its subsidiaries’ ability to, ~~June 15, 2022,~~among other things but subject to ~~a make-whole premium. We also may~~exceptions customary to reserve-based credit facilities: (i) incur additional indebtedness, (ii) make investments, (iii) enter into mergers; (iv) make or declare dividends; (v) repurchase or redeem ~~some or all of the notes at any time on or after June 15, 2022, at the applicable redemption price~~certain indebtedness; (vi) enter into certain hedges; (vii) incur liens; (viii) sell assets; and (ix) engage in ~~accordance~~certain transactions with affiliates. The New Credit Agreement requires Chesapeake to maintain compliance with the ~~terms~~following financial ratios (“Financial Covenants”): (A) a current ratio, which is the ratio of Chesapeake’s and its restricted subsidiaries’ consolidated current assets (including unused commitments under the ~~notes~~New Credit Facility but excluding certain non-cash assets) to their consolidated current liabilities (excluding the current portion of long-term debt and certain non-cash liabilities), of not less than 1.00 to 1.00; (B) a net leverage ratio, which is the ~~indenture and supplemental indenture governing the notes. In addition, subject to certain conditions, we may redeem~~ratio of total indebtedness (less unrestricted cash up to ~~35% of the aggregate principal amount of the notes at any time prior~~a specified threshold) to ~~June 15, 2020, at a price equal to 108% of the principal amount of the notes to be redeemed using the net proceeds of certain equity offerings.~~

~~In the Current Period, we retired $1.609 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases~~Consolidated EBITDAX (as defined in the ~~open market, tender offers or repayment upon maturity~~Credit Agreement) for ~~$1.751 billion. For~~ the ~~open market repurchases and tender offers, we recorded an aggregate loss~~

In the Prior Period, we retired $2.192 billion principal amount of our outstanding senior notes and contingent convertible senior notes through purchases in the open market, tender offers or repayment upon maturity for $1.5 billion. Additionally, we privately negotiated an exchange of approximately $577 million principal amount of our outstanding senior notes and contingent convertible senior notes for 109,351,707 common shares. We recorded an aggregate gain of approximately $255 million associated with these repurchases and exchanges.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)

prior four fiscal quarters, of not greater than 3.50 to 1.00 and (C) a PV-9 coverage ratio of the net present value, discounted at 9% per annum, of the estimated future net revenues expected in the proved reserves to Chesapeake’s and its restricted subsidiaries’ total indebtedness of not less than 1.50 to 1.00 (“PV-9 Coverage Ratio”).

~~Term Loan Facility~~

~~We have a secured five-year term loan facility in an aggregate principal amount of $1.5 billion as of September 30, 2017. Our obligations~~Borrowings under the ~~facility are unconditionally guaranteed on a joint~~New Credit Agreement may be alternate base rate loans or term SOFR loans, at our election. Interest is payable quarterly for alternate base rate loans and ~~several~~at the end of the applicable interest period for term SOFR loans. Term SOFR loans bear interest at term SOFR plus an applicable rate ranging from 175 to 275 basis ~~by the same subsidiaries that guarantee our revolving credit facility, second lien notes and senior notes and are secured by first-priority liens~~points per annum, depending on the ~~same collateral securing our revolving~~percentage of the commitments utilized, plus an additional 10 basis points per annum credit ~~facility (with a position in the collateral proceeds waterfall junior to the revolving credit facility). The term loan bears~~spread adjustment. Alternate base rate loans bear interest at a rate ~~of London Interbank Offered Rate (LIBOR) plus 7.50%~~ per annum ~~subject~~equal to the greatest of: (i) the prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted term SOFR rate for a ~~1.00% LIBOR floor, or the Alternative Base Rate (ABR)~~one-month interest period plus ~~6.50%~~100 basis points, plus an applicable margin ranging from 75 to 175 basis points per annum, subject to a 2.00% ABR floor, at our option. The term loan matures in August 2021 and voluntary prepayments are subject to a make-whole premium prior to the second anniversary of the closing of the term loan, a premium to par of 4.25% from the second anniversary until but excluding the third anniversary, a premium to par of 2.125% from the third anniversary until but excluding the fourth anniversary and at par beginningdepending on the fourth anniversary. The term loan may be subject to mandatory prepayments and offers to purchase with net cash proceeds of certain issuances of debt, certain asset sales and other dispositions of collateral and upon a change of control.

~~Senior Secured Second Lien Notes~~

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

In December 2015, certain of the existing notes that were exchanged for the second lien notes were accounted for as a troubled debt restructuring (TDR). For the exchanges classified as a TDR, if the future undiscounted cash flows of the newly issued debt are less than the net carrying value of the original debt, a gain is recorded for the difference and the carrying value of the newly issued debt is adjusted to the future undiscounted cash flow amount and no future interest expense is recorded. All future interest payments on the newly issued debt reduce the carrying value.

~~Senior Notes, Contingent Convertible Senior Notes and Convertible Senior Notes~~

Our obligations under our outstanding senior notes and convertible senior notes are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Our non-guarantor subsidiaries are minor and, as such, we have not included condensed consolidating financial information in the notes to our condensed consolidated financial statements.

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

~~Revolving Credit Facility~~

We have a senior secured revolving credit facility currently subject to a $3.8 billion borrowing base that matures in December 2019. Our borrowing base may be reduced in certain circumstances, including if we dispose of a certain percentage of the ~~value of collateral securing the revolving credit facility. As of September 30, 2017, we had outstanding borrowings of $645 million~~commitments utilized. Chesapeake also pays a commitment fee on unused commitment amounts under the ~~revolving credit facility and had used $97 million~~Credit Facility ranging from 37.5 to 50 basis points per annum, depending on the percentage of the ~~revolving~~commitments utilized.

The New Credit Facility is subject to customary events of default, remedies, and cure rights for credit ~~facility for various letters~~facilities of ~~credit.~~ this nature.

Borrowings under the ~~revolving credit facility bear~~New Credit Facility bore interest, ~~at a variable rate. The terms~~inclusive of the revolving credit facility include covenants limiting, among other things, our ability to incur additional indebtedness, make investments or loans, create liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates. As of September 30,

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~2017, we were in compliance with all applicable financial covenants under the agreement and we were able to borrow the full availability under the revolving credit facility.~~

As discussed in Note 16, on October 30, 2017, we completed a scheduled borrowing base redetermination review and our lenders reaffirmed our $3.8 billion borrowing base. Our next scheduled borrowing base redetermination is scheduled for the second quarter of 2018.

During 2016, we entered into the third amendment to our revolving credit facility. The amendment granted temporary financial covenant relief, with the revolving credit facility’s existing first lien secured leverage ratio and net debt to capitalization ratio suspended until September 30, 2017 (at which point the maximum first lien secured leverage ratio became 3.50 to 1.0 through the period ending December 31, 2017 and 3.00 to 1.0 thereafter and the maximum net debt to capitalization ratio for each period will be 65%) and the interest coverage ratio maintenance covenant reduced as noted below. In addition, we agreed to grant liens and security interests on a majority of our assets, as well as maintain a minimum liquidity amount (defined as cash and cash equivalents and availability under our revolving credit facility) of $500 million until the suspension of the existing maintenance covenants ends.

The third amendment increased the interest coverage ratio to 1.2 to 1.0 for the third quarter of 2017 and 1.25 to 1.0 thereafter. The amendment also gives us the ability to incur up to $2.5 billion of first lien indebtedness secured on a pari passu basis with the existing obligationsrelated fees under the credit agreement, subject to a position in the collateral proceeds waterfall in favor of the revolving lenders and affiliated hedge providers and the other limitations on junior lien debt set forth in the credit agreement. After taking into account the term loan repurchases discussed in Note 16, the amount of additional first lien indebtedness permitted by the revolving credit facility is $1.2 billion.

~~Fair Value of Debt~~

We estimate the fair value of our senior notes based on the market value of our publicly traded debt as determined based on the yield of our senior notes (Level 1). The fair value of all other debt is based on a market approach using estimates provided byat an ~~independent investment financial data services firm (Level 2). Fair value is compared to the carrying value, excluding the impact of~~average interest rate ~~derivatives, in~~of 7.4% during the ~~table below.~~first three months of 2023. The Company has no additional secured debt outstanding as of March 31, 2023.

September 30, 2017 December 31, 2016

Carrying
Amount

Estimated
Fair Value

Carrying
Amount

Estimated
Fair Value
($ in millions)
Short-term debt (Level 1) $ —
$ —
$ 503
$ 511
Long-term debt (Level 1) $ 2,876
$ 2,861
$ 3,271
$ 3,216
Long-term debt (Level 2) $ 7,021
$ 7,035
$ 6,664
$ 6,654


4.5.			Contingencies and Commitments

Contingencies

Business Operations and Litigation and Regulatory Proceedings

~~The Company is~~We are involved in, ~~a number of litigation~~ and ~~regulatory proceedings~~expect to continue to be involved in, various lawsuits and disputes incidental to our business operations, including ~~those described below. Many of these proceedings are in early stages,~~commercial disputes, personal injury claims, royalty claims, property damage claims and many of them seek or may seek damages and penalties, the amount of which is indeterminate. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different. contract actions.

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. ~~We account for legal defense costs~~Significant judgment is required in ~~the period the costs are incurred.~~making these estimates, and our final liabilities may ultimately be materially different.

~~Regulatory and Related Proceedings.~~The ~~Company has received DOJ, U.S. Postal Service and state subpoenas seeking information on~~majority of the Company’s ~~royalty payment practices. On September 19, 2017,~~prepetition legal proceedings were settled during the DOJ informed Chesapeake that it had concluded its investigation with no action taken on these matters and matters related to the purchase and lease of oil and natural gas rights. Chesapeake has engaged in discussions with the U.S. Postal Service and state agency representatives and continues to respond to related subpoenas and demands.

On July 10, 2017, Chesapeake, its Benefits Committee, its Investment Committee and certain employees were named as defendants in a purported Employee Retirement Income Security Act of 1974 (ERISA) class action filed in the United States District Court for the Western District of Oklahoma (the “ERISA Lawsuit”). The ERISA Lawsuit alleges violations of Sections 404, 405, 409 and 502 of ERISA with respect to the Company’s common stock held in its Savings and Incentive Stock Bonus Plan (the “Plan”). The lawsuit was dismissed on August 8, 2017.

~~Business Operations.~~ Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.

Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/Chapter 11 Cases or ~~entered into arrangements with affiliates that resulted in underpayment of royalties~~will be resolved in connection with the ~~production and sale of natural gas and NGL. Plaintiffs have varying royalty provisions in their respective leases, oil and gas law varies from state~~claims reconciliation process before the Bankruptcy Court, together with actions seeking to ~~state, and royalty owners and producers differ in their interpretation of~~collect pre-petition indebtedness or to exercise control over the legal effect of lease provisions governing royalty calculations. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending lawsuits seeking damages with respect to underpayment of royalties in various states, including, but not limited to, Texas, Pennsylvania, Ohio, Oklahoma, Kentucky, Louisiana and Arkansas. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class.

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

On December 9, 2015, the Commonwealth of Pennsylvania, 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 Chesapeake violated the Pennsylvania Unfair Trade Practices and Consumer Protection Law (UTPCPL) by making improper deductions and entering into arrangements with affiliates that resulted in underpayment of royalties. The lawsuit includes other UTPCPL claims and antitrust claims, including that a joint exploration agreement to which Chesapeake is a party established unlawful market allocation for the acquisition of leases. The lawsuit seeks statutory restitution, civil penalties and costs, as well as temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid and 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 resultproperty of the Company’s divestiture of substantially all of its midstream business and most of its gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights. One of the cases includes claims of intentional interference with contractual relations and violations of antitrust lawsbankruptcy estates. Any allowed claim related to ~~purported markets for gas mineral rights, operating rights and gas gathering sources.~~

~~We believe losses are reasonably possible~~such litigation will be treated in ~~certain of~~accordance with 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.

Plan. The ~~Company is also defending lawsuits alleging various violations of the Sherman Antitrust Act and state antitrust laws. In 2016, putative class action lawsuits were filed~~Plan in the ~~U.S. District Court~~Chapter 11 Cases, which became effective on February 9, 2021, provided for the ~~Western District~~treatment of ~~Oklahoma and in Oklahoma state courts, and an individual lawsuit was filed in the U.S. District Court of Kansas, in each case~~claims against the ~~Company~~Company’s bankruptcy estates, including pre-petition liabilities that had not been satisfied or addressed during the Chapter 11 Cases. Many of these proceedings were in early stages, and ~~other defendants. The lawsuits generally allege that, since 2007~~many of them sought damages and ~~continuing through April 2013,~~penalties, the ~~defendants conspired to rig bids and depress the market for the purchases~~amount of oil and natural gas leasehold interests and properties in the Anadarko Basin containing producing oil and natural gas wells. The lawsuits seek damages, attorney’s fees, costs and interest, as well as enjoinment from adopting practices or plans that would restrain competition in a similar manner as alleged in the lawsuits.

~~Other Matters~~

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

Environmental Contingencies

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

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, oil and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded as obligations in the accompanying condensed consolidated balance ~~sheets.~~sheets; however, they are reflected in our estimates of proved reserves.

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

September 30,
2017
($ in millions)
2017 $ 331
2018 1,096
2019 1,062
2020 990
2021 894
2022 – 2035 5,214
Total $ 9,587


	March 31, 2023
Remainder of 2023	$	431
2024	558
2025	483
2026	444
2027	409
2028-2036	1,835
Total	$	4,160

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

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~Drilling Contracts~~

We have contracts with various drilling contractors to utilize drilling services at market-based pricing. These commitments are not recorded as obligations in the accompanying condensed consolidated balance sheets. As of September 30, 2017, the aggregate undiscounted minimum future payments under these drilling service commitments were approximately $31 million.

~~Oil, Natural Gas and NGL Purchase Commitments~~

We commit to purchase oil, natural gas and NGL from other owners in the properties we operate, including owners associated with our remaining volumetric production payment (VPP) transaction. Production purchases under these arrangements are based on market prices at the time of production, and the purchased oil, natural gas and NGL are resold at market prices. See ~~Volumetric Production Payments~~ ~~in Note 9 for further discussion of our VPP transactions.~~

~~Net Acreage Maintenance Commitments~~

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

Other Commitments

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

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

Certain of our oil and natural gas properties are burdened by non-operating interests, such as royalty and overriding royalty interests, including overriding royalty interests sold through our VPP transactions. As the holder of the working interest from which these interests have been created, we have the responsibility to bear the cost of developing and producing the reserves attributable to these interests. See ~~Volumetric Production Payments~~ ~~in Note 9 for further discussion of our VPP transactions.~~

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

Table of ~~September 30, 2017 and December 31, 2016 are detailed below.~~

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)


5.6.			Other Current Liabilities

Other current liabilities as of ~~September 30, 2017~~March 31, 2023 and December 31, ~~2016~~2022 are detailed ~~below.~~below:


	September 30, 2017		December 31, 2016
	($ in millions)					March 31, 2023		December 31, 2022
Revenues and royalties due others	$	474	$	543	Revenues and royalties due others	$	538	$	734
Accrued drilling and production costs	313		169		Accrued drilling and production costs	250		253
Joint interest prepayments received	72		71
Accrued hedging costs					Accrued hedging costs	4		109
Accrued compensation and benefits	195		239		Accrued compensation and benefits	34		72
Other accrued taxes	73		32		Other accrued taxes	70		84
Bank of New York Mellon legal accrual^(a)	—		440
Operating leases					Operating leases	85		86
Joint interest prepayments received					Joint interest prepayments received	37		34
Current liabilities held for sale(a)					Current liabilities held for sale(a)	91		144
Other	270		304		Other	93		111
Total other current liabilities	$	1,397	$	1,798	Total other current liabilities	$	1,202	$	1,627

(a)Current liabilities held for sale are associated with the divestiture transactions related to our Eagle Ford assets. See Note 2 for additional information.


~~(a)~~7.			In the Current Period, we received notice from the U.S. Supreme Court that it would not review our appeal of the decision by the U.S. District Court for the Southern District of New York regarding the redemption at par value of our 6.775% Senior Notes due 2019. As a result of the decision, we paid $441 million with cash on hand and borrowings under the credit facility, and the related supersedeas bond was released.Revenue

~~Other long-term liabilities as~~The following table shows revenue disaggregated by operating area and product type:


	Three Months Ended March 31, 2023
	Natural Gas		Oil		NGL		Total
Marcellus	$	617	$	—	$	—	$	617
Haynesville	402		—		—		402
Eagle Ford	23		373		38		434
Natural gas, oil and NGL revenue	$	1,042	$	373	$	38	$	1,453

Marketing revenue	$	328	$	287	$	37	$	652


	Three Months Ended March 31, 2022
	Natural Gas		Oil		NGL		Total
Marcellus	$	609	$	—	$	—	$	609
Haynesville	652		—		—		652
Eagle Ford	47		450		57		554
Powder River Basin	20		66		13		99
Natural gas, oil and NGL revenue	$	1,328	$	516	$	70	$	1,914

Marketing revenue	$	408	$	395	$	64	$	867

September 30,
2017 December 31,
2016
($ in millions)
CHK Utica ORRI conveyance obligation^(a)
$ 159
$ 160
Unrecognized tax benefits 99
97
Other 102
126
Total other long-term liabilities $ 360
$ 383

~~(a)~~

The CHK Utica L.L.C. investors’ right to receive proportionately a 3% overriding royalty interest (ORRI) in the first 1,500 net wells drilled on our Utica Shale leasehold is subject to an increase to 4% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs through 2023. The liability represents the obligation to deliver future ORRIs. As of September 30, 2017 and December 31, 2016, approximately $30 million and $43 million of the total ORRI obligations are recorded in other current liabilities, respectively.

Contents

~~Outstanding shares and the liquidation price per share of our preferred stock for the Current Period and the Prior Period are detailed below.~~

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)

Accounts Receivable

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

Accounts receivable as of March 31, 2023 and December 31, 2022 are detailed below:


	March 31, 2023		December 31, 2022
Natural gas, oil and NGL sales	$	592	$	1,171
Joint interest	260		246
Other	15		24
Allowance for doubtful accounts	(3)		(3)
Total accounts receivable, net	$	864	$	1,438


6.8.			~~Equity~~Income Taxes

~~Common Stock~~

~~A summary~~We estimate our annual effective tax rate (“AETR”) for continuing operations in recording our interim quarterly income tax provision for the various jurisdictions in which we operate. The tax effects of statutory rate changes, significant unusual or infrequently occurring items, and certain changes in the assessment of the realizability of deferred tax assets are excluded from the determination of our estimated AETR as such items are recognized as discrete items in the quarter in which they occur. Our estimated AETR during the first three months of 2023 was 22.5% as a result of projecting current and deferred federal and state income taxes and a partial valuation allowance against our anticipated net deferred asset position at December 31, 2023.

Our estimated AETR during the first three months of 2022 was 5.7% as a result of projecting current federal and state income taxes and maintaining a full valuation allowance against our net deferred asset position. Although we projected a current federal and state tax liability, a benefit was recorded during the first three months of 2022 due to the application of the AETR to the book net loss before income taxes during the first three months of 2022.

As of December 31, 2022, we were in a net deferred tax asset position and anticipate being in a net deferred tax asset position as of December 31, 2023. Based on all available positive and negative evidence, including projections of future taxable income, we believe it is more likely than not that some of our deferred tax assets will not be realized. As such, a partial valuation allowance was recorded against our net deferred tax asset position for federal and state purposes as of March 31, 2023 and December 31, 2022.

On August 16, 2022, the President of the United States signed into law the Inflation Reduction Act of 2022, which includes provisions for a 15% corporate alternative minimum tax on book income for companies whose average book income exceeds $1 billion for any three consecutive years preceding the tax year and a 1% excise tax on stock buybacks. These changes are generally in ~~our common shares issued~~effect for tax years beginning after December 31, 2022. We do not currently project that we will be subject to the alternative minimum tax on book income for the ~~Current Period~~2023 tax period, and the ~~Prior Period is detailed below.~~impact of the 1% excise tax was immaterial during the first three months of 2023.

Nine Months Ended
September 30,
2017 2016
(in thousands)
Shares issued as of January 1 896,279
664,796
Exchange of convertible notes —
55,428
Exchange of senior notes —
53,924
Exchange/conversion of preferred stock 9,966
1,021
Restricted stock issuances (net of forfeitures and cancellations) 2,417
1,852
Shares issued as of September 30 908,662

777,021

~~During the Current Period, our shareholders approved an amendment to our certificate~~Table of ~~incorporation to increase our authorized common stock to 2,000,000,000 shares, par value $0.01 per share.~~

~~Preferred Stock~~

5.75% 5.75% (A) 4.50%
5.00%
(2005B)
(in thousands)
Shares outstanding as of January 1, 2017 843
476
2,559
1,962
Preferred stock conversions/exchanges^(a)
(73 ) (13 ) —
(151 )
Shares outstanding as of September 30, 2017 770
463
2,559
1,811

Shares outstanding as of January 1, 2016 1,497
1,100
2,559
2,096
Preferred stock conversions/exchanges^(b)
(25 ) (1 ) —
—
Shares outstanding as of September 30, 2016 1,472
1,099
2,559
2,096

Liquidation price per share $ 1,000
$ 1,000
$ 100
$ 100

~~(a)~~

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


~~(b)~~	In the Prior Period, holders of our 5.75% Cumulative Convertible Preferred Stock converted 24,601 shares into 975,488 shares of common stock and holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock converted 1,201 shares into 46,018 shares of common stock.

For the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, 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 condensed consolidated statements of operations were $8 million, $7 million, $25 million and $21 million, respectively.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)


9.			Equity

Dividends

~~Dividends declared~~In May 2021, we initiated a new annual dividend on our ~~preferred~~shares of common stock, ~~are reflected as adjustments~~expected to ~~retained earnings~~be paid quarterly. During the first three months of 2023 and 2022, we made dividend payments of $175 million ($1.29 per share) and $210 million ($1.7675 per share), respectively.

On May 2, 2023, we declared a quarterly dividend payable of $1.18 per share, which will be paid on June 6, 2023 to stockholders of record at the ~~extent~~close of business on May 18, 2023. The dividend consists of a ~~surplus~~base quarterly dividend in the amount of ~~retained earnings exists after giving effect~~$0.55 per share and a variable quarterly dividend in the amount of $0.63 per share.

Share Repurchase Program

As of December 2, 2021, the Company was authorized to purchase up to $1.0 billion of the ~~dividends. To~~Company’s common stock and/or warrants under a share repurchase program. In June 2022, our Board of Directors authorized an expansion of the ~~extent retained earnings are insufficient~~share repurchase program by $1.0 billion, bringing the total authorized share repurchase amount to ~~fund~~$2.0 billion for stock and/or warrants. The share repurchase program will expire on December 31, 2023.

In March 2022, we commenced our share repurchase program. During the ~~distributions, payments constitute a return~~first three months of ~~contributed capital rather than earnings~~2023, we repurchased 0.8 million shares of common stock for an aggregate price of $60 million, inclusive of shares for which cash settlement occurred in early April. During the first three months of 2022, we repurchased 1 million shares of common stock for an aggregate price of $83 million. The repurchased shares of common stock were retired and ~~are accounted for~~recorded 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 orand retained earnings. All share repurchases made after January 1, 2023, are subject to a ~~combination thereof, at our option. Dividends~~1% excise tax on ~~both series~~share repurchases, as enacted under the Inflation Reduction Act of 2022. We are able to net this 1% excise tax on share repurchases against the issuance of shares of our ~~5.75% Cumulative Convertible Non-Voting Preferred~~common stock. The impact of this 1% excise tax was immaterial during the first three months of 2023.

Warrants


	Class A Warrants	Class B Warrants	Class C Warrants(a)
Outstanding as of December 31, 2022	4,495,004	4,404,564	4,006,229
Converted into New Common Stock(b)	(3,000)	(1,000)	(170)

Outstanding as of March 31, 2023	4,492,004	4,403,564	4,006,059

_________________________________________

(a)As of March 31, 2023, we had 1,489,337 of reserved Class C Warrants.

(b)During the first three months of 2023, we issued 4,654 shares of New Common Stock ~~are payable only in cash.~~as a result of Warrant exercises.


10.			Share-Based Compensation

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

Restricted Stock Units. During the first three months of 2023, we ~~suspended dividend payments~~granted RSUs to employees and non-employee directors under the LTIP, which will vest over a three-year period. The fair value of RSUs is based on ~~our convertible preferred stock to provide additional liquidity in~~ the ~~depressed commodity~~closing sales price ~~environment. In the Current Period, we reinstated the payment of dividends on each series~~ of our ~~outstanding convertible preferred~~common stock on the date of grant, and ~~paid our dividends in arrears.~~

~~Accumulated Other Comprehensive Income (Loss)~~

~~For~~compensation expense is recognized ratably over the ~~Current Period and~~requisite service period. A summary of the ~~Prior Period,~~ changes in ~~accumulated other comprehensive income (loss) for cash flow hedges, net~~unvested RSUs is presented below:

Table of ~~tax, are detailed below.~~

Nine Months Ended
September 30,
2017 2016
($ in millions)
Balance, as of January 1 $ (96 ) $ (99 )
Other comprehensive income (loss) before reclassifications 4
(23 )
Amounts reclassified from accumulated other comprehensive income 25
21
Net other comprehensive income (loss) 29
(2 )
Balance, as of September 30 $ (67 ) $ (101 )

Contents

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)


7.	~~Share-Based Compensation~~

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

~~Equity-Classified Awards~~

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


						Unvested Restricted Stock Units	Weighted Average Grant Date Fair Value Per Share
	Shares of Unvested Restricted Stock		Weighted Average Grant Date Fair Value			(in thousands)
	(in thousands)
Unvested restricted stock as of January 1, 2017	9,092		$	11.39
Unvested as of December 31, 2022					Unvested as of December 31, 2022	957	$	68.91
Granted	9,872		$	5.40	Granted	414	$	71.66
Vested	(4,481	)	$	13.63	Vested	(137)	$	74.36
Forfeited	(942	)	$	8.85	Forfeited	(12)	$	59.85
Unvested restricted stock as of September 30, 2017	13,541		$	6.46
Unvested as of March 31, 2023					Unvested as of March 31, 2023	1,222	$	69.31

The aggregate intrinsic value of ~~restricted stock~~RSUs that vested during the ~~Current Period~~first three months of 2023 was approximately ~~$25~~$10 million based on the stock price at the time of vesting.

As of ~~September 30, 2017~~,March 31, 2023, there was approximately ~~$59~~ $73 million of total unrecognized compensation expense related to unvested ~~restricted stock.~~RSUs. The expense is expected to be recognized over a weighted average period of ~~approximately 1.97~~approximately 2.72 years.

~~Stock Options.~~ InPerformance Share Units. During the ~~Current Period and the Prior Period,~~first three months of 2023, we granted ~~members of~~PSUs to senior management ~~stock options that~~under the LTIP, which will generally vest ~~ratably~~ over a three-year ~~period. Each stock option award has an exercise price equal to the closing price~~period and will be settled in shares. The performance criteria include total shareholder return (“TSR”) and relative TSR (“rTSR”) and could result in a total payout between 0% - 200% of the ~~Company’s common stock on the grant date. Outstanding options expire seven years to ten years from the date of grant.~~

~~We utilize the Black-Scholes option pricing model to measure the fair value of stock options.~~target units. The expected life of an option is determined using the simplified method. Volatility assumptions are estimated based on an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the ~~stock options~~PSUs was measured on the grant date using a Monte Carlo simulation, and compensation expense is recognized ratably over the requisite service period because these awards depend on a combination of service and market criteria.

The following table presents the assumptions used in the valuation of the PSUs granted in ~~the Current Period.~~

2023.



~~Expected option life – years~~Assumption			~~6.0~~		TSR, rTSR
~~Volatility~~	~~62.42~~	%
Risk-free interest rate	~~2.17~~3.85		%
~~Dividend yield~~Volatility			—64.4	%

For PSUs granted, the TSR component can range from 0% to 100% and the operational component can range from 0% to 100%, resulting in a maximum payout of 200%. Compensation expense associated with PSU grants is recognized over the service period based on the graded-vesting method. The value of the PSU awards at the end of each reporting period is dependent upon the Company’s estimates of the underlying performance measures. The payout percentage for all PSU grants is capped at 100% if the Company’s absolute TSR is less than zero. The Company utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the PSUs.

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~A summary of the changes in unvested PSUs is presented below:

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~


	Unvested Performance Share Units	Weighted Average Grant Date Fair Value Per Share
	(in thousands)
Unvested as of December 31, 2022	276	$	88.28
Granted	131	$	78.78
Vested	—	$	—
Forfeited	—	$	—
Unvested as of March 31, 2023	407	$	85.23

~~(Unaudited)~~

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

Number of
Shares
Underlying
Options

Weighted
Average
Exercise Price Per Share

Weighted
Average
Contract Life in Years

Aggregate
Intrinsic
Value^(a)
(in thousands) ($ in millions)
Outstanding as of January 1, 2017 8,593
$ 11.88
7.22 $ 14
Granted 9,226
$ 5.45

Exercised —
$ —
$ —
Expired (524 ) $ 18.45

Forfeited (904 ) $ 9.91

Outstanding as of September 30, 2017 16,391
$ 8.16
8.04 $ 2
Exercisable as of September 30, 2017 4,490
$ 15.22
5.49 $ 1


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

As of ~~September 30, 2017~~March 31, 2023, there was ~~$26~~approximately $23 million of total unrecognized compensation expense related to ~~stock options.~~unvested PSUs. The expense is expected to be recognized over a weighted average period of ~~approximately 2.28 years.~~approximately 2.26 years.

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
($ in millions)
General and administrative expenses $ 9
$ 10
$ 29
$ 28
Oil and natural gas properties 3
4
10
13
Oil, natural gas and NGL production expenses 2
4
9
10
Marketing, gathering and compression expenses —
—
—
1
Total restricted stock and stock option compensation $ 14
$ 18
$ 48
$ 52

~~Liability-Classified Awards~~

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



~~Volatility~~	~~87.16~~	%
~~Risk-free interest rate~~	~~1.51~~	%
~~Dividend yield for value of awards~~	—	%

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)

~~The following table presents a summary of our 2017, 2016~~RSU and ~~2015 PSU awards.~~

Grant Date
Fair Value
September 30, 2017
Units Fair Value Vested Liability
($ in millions) ($ in millions)
2017 Awards:
Payable 2020 1,217,774
$ 8
$ 6
$ 2
2016 Awards:
Payable 2019 2,348,893
$ 10
$ 9
$ 8
2015 Awards:
Payable 2018 629,694
$ 13
$ 1
$ 1

PSU Compensation.

We recognized the following compensation costs, ~~(credits)~~net of actual forfeitures, related to RSUs and PSUs for the ~~Current Quarter, the Prior Quarter, the Current Period and the Prior Period.~~periods presented:


	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022
General and administrative expenses	$	6	$	3
Natural gas and oil properties	1		1
Production expense	1		—
Total RSU and PSU compensation	$	8	$	4
Related income tax benefit	$	1	$	—

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
($ in millions)
General and administrative expenses $ (2 ) $ 7
$ (4 ) $ 10
Restructuring and other termination costs —
—
—
1
Total PSU compensation $ (2 ) $ 7
$ (4 ) $ 11

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~


8.11.			Derivative and Hedging Activities

~~Chesapeake uses~~We use derivative instruments to reduce ~~its~~our exposure to fluctuations in future commodity prices and to protect ~~its~~our expected operating cash flow against significant market movements or volatility. These commodity derivative financial instruments include financial price swaps, basis protection swaps, collars, three-way collars and options. All of our ~~commodity~~natural gas and oil 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~~We do not intend to hold or issue derivative financial instruments for speculative trading purposes and have elected not to designate any of our derivative instruments ~~were designated~~ for hedge accounting astreatment.

As of ~~September 30, 2017 and~~ December 31, ~~2016.~~

~~Oil, Natural Gas and NGL Derivatives~~

As2022, approximately $65 million of ~~September 30, 2017~~ ~~and December 31, 2016, our oil,~~derivative liabilities (notional volume of 9.6 bcf of natural gas and ~~NGL~~notional volume of 4.8 mmbbls of oil) were classified as liabilities held for sale. These derivative instruments ~~consisted~~were novated to WildFire Energy I LLC upon completion of the ~~following types~~sale of ~~instruments:~~

~~Swaps: Chesapeake receives~~ a ~~fixed price and pays a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain~~portion of our ~~swap trades, we may sell call options and call swaptions.~~

Eagle Ford assets on March 20, 2023. See Note 2 for more details.

~~Options~~: Chesapeake sells, and occasionally buys, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options and Chesapeake receives the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

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

~~Collars~~: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by Chesapeake 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. Chesapeake receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity.

The estimated fair values of our ~~oil,~~ natural gas and ~~NGL~~oil derivative instrument assets (liabilities) as of ~~September 30, 2017~~March 31, 2023 and December 31, ~~2016~~2022 are provided ~~below.~~ below:


	March 31, 2023			December 31, 2022
	Notional Volume	Fair Value		Notional Volume	Fair Value
Natural gas (Bcf):
Fixed-price swaps	369	$	(2)	382	$	(494)
Collars	706	571		721	49
Three-way collars	3	1		4	(2)
Call options	—	—		18	(22)
Basis protection swaps	624	(62)		652	(32)
Total natural gas	1,702	508		1,777	(501)
Oil (MMBbls):
Fixed-price swaps	—	—		1	(32)
Collars	2	10		2	7
Basis protection swaps	4	1		6	1
Total oil	6	11		9	(24)
Total estimated fair value		$	519		$	(525)

September 30, 2017 December 31, 2016
Volume Fair Value Volume Fair Value
($ in millions) ($ in millions)
Oil (mmbbl):
Fixed-price swaps 18
$ (17 ) 23
$ (140 )
Three Way Collars 2
(2 ) —
—
Call options 1
—
5
(1 )
Call swaptions 2
(7 ) —
—
Basis protection swaps 3
(1 ) —
—
Total oil 26
(27 ) 28
(141 )
Natural gas (tbtu):
Fixed-price swaps 696
38
719
(349 )
Collars 71
8
60
(9 )
Call options 121
(7 ) 114
—
Basis protection swaps 26
(1 ) 31
(5 )
Total natural gas 914
38
924
(363 )
NGL (mmgal):
Fixed-price swaps 15
(2 ) 53
—
Total estimated fair value $ 9
$ (504 )

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)

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

~~Interest Rate Derivatives~~

~~As of September 30, 2017 and December 31, 2016, there were no interest rate derivatives outstanding.~~

We have terminated fair value hedges related to certain of our senior notes. Gains and losses related to these terminated hedges will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next three years, we will recognize $2 million in net gains related to these transactions.

~~Foreign Currency Derivatives~~

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

~~Supply Contract Derivatives~~

From time to time and in the normal course of business, our marketing subsidiary enters into supply contracts under which we commit to deliver a predetermined quantity of natural gas to certain counterparties in an attempt to earn attractive margins. Under certain contracts, we receive a sales price that is based on the price of a product other than natural gas, thereby creating an embedded derivative requiring bifurcation. In the Prior Quarter, we sold a long-term natural gas supply contract to a third party for cash proceeds of $146 million, which is included in marketing, gathering and compression revenues as a realized gain. We reversed the cumulative unrealized gains, resulting in an unrealized loss of $280 million in the Prior Quarter and $297 million in Prior Period, respectively.

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~Effect of Derivative Instruments – Condensed Consolidated Balance Sheets~~

The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of ~~September 30, 2017~~March 31, 2023 and December 31, ~~2016~~2022 on a gross basis and after same-counterparty netting:


											Gross Fair Value(a)		Amounts Netted in the Condensed Consolidated Balance Sheets		Net Fair Value Presented in the Condensed Consolidated Balance Sheets
Balance Sheet Classification	Gross Fair Value			Amounts Netted in the Condensed Consolidated Balance Sheets			Net Fair Value Presented in the Condensed Consolidated Balance Sheet
	($ in millions)
As of September 30, 2017
As of March 31, 2023										As of March 31, 2023
Commodity Contracts:										Commodity Contracts:
Short-term derivative asset	$	57		$	(29	)	$	28		Short-term derivative asset	$	602	$	(138)	$	464
Long-term derivative asset										Long-term derivative asset	178		(56)		122
Short-term derivative liability	(37		)	29			(8		)	Short-term derivative liability	(163)		138		(25)
Long-term derivative asset	1			(1		)	—
Long-term derivative liability	(11		)	—			(11		)	Long-term derivative liability	(98)		56		(42)
Total commodity contracts	10			(1		)	9
Total derivatives	$	10		$	(1	)	$	9		Total derivatives	$	519	$	—	$	519

As of December 31, 2016
As of December 31, 2022										As of December 31, 2022
Commodity Contracts:										Commodity Contracts:
Short-term derivative asset	$	1		$	(1	)	$	—		Short-term derivative asset	$	200	$	(166)	$	34
Long-term derivative asset										Long-term derivative asset	87		(40)		47
Short-term derivative liability	(490		)	1			(489		)	Short-term derivative liability	(598)		166		(432)
Long-term derivative liability	(15		)	—			(15		)	Long-term derivative liability	(214)		40		(174)
Total commodity contracts	(504		)	—			(504		)
Foreign Currency Contracts:^(a)
Short-term derivative liability	(73		)	—			(73		)
Total foreign currency contracts	(73		)	—			(73		)
Total derivatives	$	(577	)	$	—		$	(577	)	Total derivatives	$	(525)	$	—	$	(525)


~~(a)~~	~~Designated as cash flow hedging instruments.~~

~~As of~~ ~~September 30, 2017~~ ~~and December 31, 2016, we did not have any cash collateral balances for these derivatives.~~

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~Effect of Derivative Instruments – Condensed Consolidated Statements of Operations~~

~~The components of oil, natural gas and NGL revenues for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period~~(a)These financial assets (liabilities) are ~~presented~~measured at fair value on a recurring basis utilizing significant other observable inputs; see further discussion on fair value measurements below.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
($ in millions)
Oil, natural gas and NGL revenues $ 1,049
$ 1,048
$ 3,275
$ 2,744
Gains (losses) on undesignated oil, natural gas
and NGL derivatives
(62 ) 136
477
(110 )
Losses on terminated cash flow hedges (8 ) (7 ) (25 ) (24 )
Total oil, natural gas and NGL revenues $ 979
$ 1,177
$ 3,727
$ 2,610

~~The components of marketing, gathering and compression revenues for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
($ in millions)
Marketing, gathering and compression revenues $ 964
$ 1,379
$ 3,250
$ 3,538
Losses on undesignated supply contract derivatives —
(280 ) —
(297 )
Total marketing, gathering and compression revenues $ 964
$ 1,099
$ 3,250
$ 3,241

~~The components of interest expense for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
($ in millions)
Interest expense on senior notes $ 135
$ 141
$ 407
$ 446
Interest expense on term loan 34
14
98
14
Amortization of loan discount, issuance costs and other 13
9
28
27
Amortization of premium associated with troubled debt restructuring (29 ) (41 ) (112 ) (124 )
Interest expense on revolving credit facility 11
10
28
27
Gains on terminated fair value hedges (1 ) (1 ) (1 ) (2 )
Losses on undesignated interest rate derivatives —
—
1
—
Capitalized interest (49 ) (59 ) (147 ) (191 )
Total interest expense $ 114
$ 73
$ 302
$ 197

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

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

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

Three Months Ended September 30,
2017 2016
Before
Tax   After
Tax   Before
Tax   After
Tax
($ in millions)
Balance, beginning of period $ (132 ) $ (75 ) $ (163 ) $ (104 )
Net change in fair value —
—
(4 ) (4 )
Losses reclassified to income 8
8
7
7
Balance, end of period $ (124 ) $ (67 ) $ (160 ) $ (101 )

Nine Months Ended September 30,
2017 2016
Before
Tax   After
Tax   Before
Tax   After
Tax
($ in millions)
Balance, beginning of period $ (153 ) $ (96 ) $ (160 ) $ (99 )
Net change in fair value 4
4
(23 ) (23 )
Losses reclassified to income 25
25
23
21
Balance, end of period $ (124 ) $ (67 ) $ (160 ) $ (101 )

~~The accumulated other comprehensive loss, as of~~ ~~September 30, 2017~~, represents the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months are yet to occur. Remaining deferred gain or loss amounts will be recognized in earnings in the month for which the original contract months are to occur. As of September 30, 2017, we expect to transfer approximately $19 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 the Company 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 September 30, 2017, our oil, natural gas and NGL derivative instruments were spread among 10 counterparties.

~~Hedging Arrangements~~

Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under our revolving credit facility. The contracts entered into with these counterparties are secured by the same collateral that secures our revolving credit facility, which allows us to reduce any letters of credit posted as security with those counterparties. In addition, we enter into bilateral hedging agreements with other counterparties. The counterparties’ and our obligations under the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds.

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

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

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 March 31, 2023, our natural gas and oil derivative instruments were spread among 12 counterparties.

Hedging Arrangements

Certain of our hedging arrangements are with counterparties that were also lenders (or affiliates of lenders) under our New Credit Facility. The ~~following table provides information~~contracts entered into with these counterparties are secured by the same collateral that secures the New 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. As of March 31, 2023, we did not have any cash or letters of credit posted as collateral for ~~financial assets (liabilities) measured at fair value on a recurring basis as of~~ ~~September 30, 2017~~ ~~and December 31, 2016:~~our commodity derivatives.

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 September 30, 2017
Derivative Assets (Liabilities):
Commodity assets $ —
$ 55
$ 2
$ 57
Commodity liabilities —
(38 ) (10 ) (48 )
Total derivatives $ —
$ 17
$ (8 ) $ 9

As of December 31, 2016
Derivative Assets (Liabilities):
Commodity assets $ —
$ 1
$ —
$ 1
Commodity liabilities —
(495 ) (10 ) (505 )
Foreign currency liabilities —
(73 ) —
(73 )
Total derivatives $ —
$ (567 ) $ (10 ) $ (577 )

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS –- (Continued)

(Unaudited)

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

Commodity
Derivatives

Supply
Contracts
($ in millions)
Balance, as of January 1, 2017 $ (10 ) $ —
Total gains (losses) (realized/unrealized):
Included in earnings^(a)
1
—
Total purchases, issuances, sales and settlements:
Settlements 1
—
Balance, as of September 30, 2017 $ (8 ) $ —

Balance, as of January 1, 2016 $ (91 ) $ 297
Total gains (losses) (realized/unrealized):
Included in earnings^(a)
12
(118 )
Total purchases, issuances, sales and settlements:
Settlements 49
(33 )
Sales —
(146 )
Balance, as of September 30, 2016 $ (30 ) $ —

(a)
Oil, Natural Gas
and NGL
Sales

Marketing, Gathering
and Compression
Revenue

2017 2016 2017 2016
($ in millions)
Total gains (losses) included in earnings for the period $ 1
$ 12
$ —
$ (118 )
Change in unrealized gains (losses) related to assets still held at reporting date $ (7 ) $ (1 ) $ —
$ —

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

The significant unobservable inputs for Level 3 derivative contracts include unpublished forward prices of natural gas, market volatility and credit risk of counterparties. Changes in these inputs impact the fair value measurement of our derivative contracts, which is based on an estimate derived from option models. For example, an increase or decrease in the forward prices and volatility of oil and natural gas prices decreases or increases the fair value of oil and natural gas derivatives, and adverse changes to our counterparties’ creditworthiness decreases the fair value of our derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of September 30, 2017:

Instrument
Type

Unobservable
Input
Range
Weighted
Average
Fair Value
September 30, 2017
($ in millions)
Oil trades Oil price volatility curves 15.30% – 26.67% 23.43% $ (9 )
Natural gas trades
Natural gas price volatility
curves
19.58% – 63.01% 38.24% $ 1

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~


9.12.			~~Oil and Natural Gas Property Transactions~~Investments

~~Under full cost accounting rules, we accounted for~~Momentum Sustainable Ventures LLC. During the ~~sales~~fourth quarter of ~~oil and~~2022, Chesapeake entered into an agreement with Momentum Sustainable Ventures LLC to build a new natural gas properties discussed below as adjustments to capitalized costs, with no recognition of gain or loss as the sales did not involve a significant change in proved reserves or significantly alter the relationship between costsgathering pipeline and ~~proved reserves.~~

~~In the Current Period, we sold portions of our acreage~~carbon capture and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $915 million, subject to certain customary closing adjustments. Included in the sales were approximately 119,500 net acres and interests in 576 wells that were producing approximately 80 mmcf of gas per day at the time of closing.

~~Also in the Current Quarter and the Current Period, we received proceeds of $248 million and $331 million, respectively, net of post-closing adjustments, for the sale of other oil and~~sequestration project (“CCUS”), which will gather natural gas ~~properties covering various operating areas.~~

~~In the Prior Quarter, we acquired oil and natural gas properties~~produced in the Haynesville Shale for ~~approximately $85 million. In the Prior Quarter and the Prior Period, we sold certain~~re-delivery to Gulf Coast markets, including LNG export. The pipeline is expected to have an initial capacity of our noncore oil and natural gas properties for net proceeds of approximately $26 million and $988 million, respectively, after post-closing adjustments. In conjunction with certain of these sales, we purchased oil and natural gas interests previously sold1.7 Bcf/d expandable to ~~third parties in connection with four of our VPP transactions for approximately $259 million. A majority~~2.2 Bcf/d. The carbon capture portion of the ~~acquired interests were sold in the asset divestitures discussed above~~project anticipates capturing and ~~we no longer have any further commitments or obligations related~~permanently sequestering up to ~~these VPPs.~~2.0 million tons per annum of CO2. The ~~asset divestitures cover various operating areas.~~

~~Volumetric Production Payments~~

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

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

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

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~As of September 30, 2017, we had the following VPP outstanding:~~

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

~~The volumes produced on behalf of our VPP buyers during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period were as follows:~~

Three Months Ended September 30, 2017 Three Months Ended September 30, 2016
VPP # Oil Natural Gas NGL Total Oil Natural Gas NGL Total
(mbbl) (bcf) (mbbl) (bcfe) (mbbl) (bcf) (mbbl) (bcfe)
   9 34.4
2.9
79.9
3.6
37.6
3.2
85.9
4.0
   1^(a)
—
—
—
—
—
3.1
—
3.1
34.4
2.9
79.9
3.6
37.6
6.3
85.9
7.1

Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016
VPP # Oil Natural Gas NGL Total Oil Natural Gas NGL Total
(mbbl) (bcf) (mbbl) (bcfe) (mbbl) (bcf) (mbbl) (bcfe)
10^(a)
—
—
—
—
108.0
3.0
368.7
5.8
   9 105.5
9.0
243.9
11.0
115.5
9.9
262.8
12.2
   4^(a)
—
—
—
—
20.0
3.8
—
3.9
   3^(a)
—
—
—
—
—
2.5
—
2.5
   2^(a)
—
—
—
—
—
1.5
—
1.5
   1^(a)
—
—
—
—
—
9.5
—
9.5
105.5
9.0
243.9
11.0
243.5
30.2
631.5
35.4


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

~~The volumes remaining to be delivered on behalf of our VPP buyers as of~~ ~~September 30, 2017~~ ~~were as follows:~~

Volume Remaining as of September 30, 2017
VPP # Term Remaining Oil Natural Gas NGL Total
(in months) (mmbbl) (bcf) (mmbbl) (bcfe)
9 41 0.4
36.8
1.0
45.1

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~


~~10.~~	~~Variable Interest Entities~~

We consolidate the activities of VIEs for which we are the primary beneficiary. 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.

Chesapeake Granite Wash Trust (the “Trust”) is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust and because the royalty interest owners, other than Chesapeake, do not have the ability to exercise substantial liquidation rights. Our ownership in the Trust and our previous obligations under the development agreement constitute variable interests. On June 30, 2017, the Trust’s subordinated units, all of which were held by Chesapeake, converted to common units. We continue to consolidate the activities of the Trust as we are the primary beneficiary of the Trust because (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our operation of the majority of the producing wells and the completed development wells, and (ii) we have the obligation to absorb losses that potentially could be significant to the Trust. As a result, we consolidate the Trust in our financial statements, and the common units of the Trust owned by third parties are reflected as a noncontrolling interest. As of September 30, 2017 and December 31, 2016, we had $253 million and $257 million, respectively, of noncontrolling interests on our condensed consolidated balance sheets attributable to the Trust. In the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we had $1 million, $1 million, $3 million and $1 million, respectively, of net income attributable to the Trust’s noncontrolling interests recorded in our condensed consolidated statements of operations.

The Trust is a consolidated entity whose legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake. In consolidation, as of ~~September 30, 2017~~, $1 million of cash and cash equivalents, $488 million of proved oil and natural gas properties, $460 million of accumulated depreciation, depletion and amortization and $4 million of other current liabilities were attributable to the Trust. We have presented parenthetically on the face of the condensed consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake.

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~


~~11.~~	~~Impairments~~

~~Impairments of Oil and Natural Gas Properties~~

Our proved oil and natural gas properties are subject to quarterly full cost ceiling tests. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. Estimated future net revenues for the quarterly ceiling limit are calculated using the average of commodity prices on the first day of the month over the trailing 12-month period. In the Prior Quarter and the Prior Period, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment in the carrying value of our oil and natural gas properties of $497 million and $2.564 billion, respectively.

~~Impairments of Fixed Assets and Other~~

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
($ in millions)
Barnett Shale exit costs $ —
$ 616
$ —
$ 616
Gathering systems —
96
—
96
Natural gas compressors —
32
—
52
Buildings and land 1
7
3
14
Other 8
—
423
17
Total impairments of fixed assets and other $ 9
$ 751
$ 426
$ 795

~~Barnett Shale Exit Costs.~~ In October 2016, we conveyed our interests in the Barnett Shale operating area located in north central Texas and simultaneously terminated most of our future commitments associated with this asset. As a result of this transaction, we accrued $334 million of charges in the Prior Quarter related to the termination of a natural gas gathering agreement associated with the Barnett Shale assets. We recognized an impairment charge of $282 million in the Prior Quarter related to these assets representing the difference between the carrying amount and the fair value of the assets, less the anticipated costs to sell.

~~Gathering Systems, Natural Gas Compressors, Buildings and Land.~~ In the Prior Quarter we entered into a purchase and sale agreement to sell the majority of our upstream and midstream assets in the Devonian Shale located in West Virginia and Kentucky. We recognized an impairment charge of $134 million in the Prior Quarterpipeline in-service is projected for ~~these assets for the difference between the carrying amount and the fair value of the assets, less the anticipated costs to sell.~~

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

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

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~


~~12.~~	~~Income Taxes~~

A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, and we consider the tax consequences in the jurisdiction where taxable income is generated, to determine whether a valuation allowance is required. The evidence can include our current financial position, our results of operations (both actual and forecasted), the expected reversal of our deferred tax liabilities, and various tax planning strategies as well as the current and forecasted business economics of our industry.

Based on our estimated operating results for the subsequent quarter, we project being in a net deferred tax asset position as of December 31, 2017. We believe it is more likely than not that these deferred tax assets will not be realized. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of objective negative evidence evaluated is the projected cumulative loss incurred over the three-year period ending December 31, 2017. The objective negative evidence limits our ability to consider other subjective positive evidence, such as our projections for future growth. The amount of the deferred tax asset considered realizable, however, could be adjusted if objective negative evidence in the form of cumulative losses is no longer present or if estimates of future taxable income are increased and additional weight is given to subjective evidence, such as future expected growth. A valuation allowance was recorded against our net deferred tax asset as of both December 31, 2016 and September 30, 2017.


~~13.~~	~~Fair Value Measurements~~

~~Recurring Fair Value Measurements~~

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

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

~~Financial Assets (Liabilities). The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of~~ ~~September 30, 2017~~ ~~and December 31, 2016:~~

Quoted
Prices in
Active
Markets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total
Fair Value
($ in millions)
As of September 30, 2017
Financial Assets (Liabilities):
Other current assets $ 57
$ —
$ —
$ 57
Other current liabilities (58 ) —
—
(58 )
Total $ (1 ) $ —
$ —
$ (1 )

As of December 31, 2016
Financial Assets (Liabilities):
Other current assets $ 49
$ —
$ —
$ 49
Other current liabilities (51 ) —
—
(51 )
Total $ (2 ) $ —
$ —
$ (2 )

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

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

~~Nonrecurring Fair Value Measurements~~

~~See Note 11 regarding nonrecurring fair value measurements.~~


~~14.~~	~~Segment Information~~

As of September 30, 2017, we have two reportable operating segments. Our exploration and production operating segment is responsible for finding and producing oil, natural gas and NGL, while our marketing, gathering and compression operating segment is responsible for marketing, gathering and compression of oil, natural gas and NGL.

Revenues from the sale of oil, natural gas and NGL related to Chesapeake’s ownership interests by our marketing, gathering and compression operating segment are reflected as revenues within our exploration and production operating segment. These amounts totaled $1.030 billion, $1.025 billion, $3.200 billion and $2.656 billion for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, respectively.

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

Exploration
and
Production

Marketing,
Gathering
and
Compression
Other
Intercompany
Eliminations

Consolidated
Total
($ in millions)
Three Months Ended
September 30, 2017

Revenues $ 979
$ 1,994
$ —
$ (1,030 ) $ 1,943
Intersegment revenues —
(1,030 ) —
1,030
—
Total Revenues $ 979
$ 964
$ —
$ —
$ 1,943
Income (Loss) Before
Income Taxes
$ (14 ) $ 7
$ (10 ) $ —
$ (17 )

Three Months Ended
September 30, 2016

Revenues $ 1,177
$ 2,124
$ —
$ (1,025 ) $ 2,276
Intersegment revenues —
(1,025 ) —
1,025
—
Total Revenues $ 1,177
$ 1,099
$ —
$ —
$ 2,276
Income (Loss) Before
Income Taxes
(as previously reported)
$ (710 ) $ (211 ) $ (231 ) $ (2 ) $ (1,154 )
Income (Loss) Before
Income Taxes
(as revised)^(a)
$ (642 ) $ (339 ) $ (231 ) $ (2 ) $ (1,214 )

Nine Months Ended
September 30, 2017

Revenues $ 3,727
$ 6,450
$ —
$ (3,200 ) $ 6,977
Intersegment revenues —
(3,200 ) —
3,200
—
Total Revenues $ 3,727
$ 3,250
$ —
$ —
$ 6,977
Income (Loss) Before
Income Taxes
$ 1,094
$ (440 ) $ (32 ) $ (1 ) $ 621

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

Exploration
and
Production

Marketing,
Gathering
and
Compression
Other
Intercompany
Eliminations

Consolidated
Total
($ in millions)
Nine Months Ended
September 30, 2016

Revenues $ 2,610
$ 5,897
$ —
$ (2,656 ) $ 5,851
Intersegment revenues —
(2,656 ) —
2,656
—
Total Revenues $ 2,610
$ 3,241
$ —
$ —
$ 5,851
Income (Loss) Before
Income Taxes
(as previously reported)
$ (3,360 ) $ (215 ) $ (248 ) $ (2 ) $ (3,825 )
Income (Loss) Before
Income Taxes
(as revised)^(a)
$ (3,465 ) $ (343 ) $ (248 ) $ (2 ) $ (4,058 )

As of
September 30, 2017

Total Assets $ 10,451
$ 923
$ 994
$ (387 ) $ 11,981
As of
December 31, 2016

Total Assets $ 11,249
$ 1,118
$ 1,059
$ (398 ) $ 13,028


~~(a)~~	~~We have revised the amounts presented in the Prior Quarter and the Prior Period. The impact of the errors was not material to any previously issued financial statements.~~

Table of the effects of hedging relationships, assessment of hedge effectiveness and disclosures. The accounting standards update is effective for annual interim periods beginning after December 15, 2018, including interim periods within those annual periods. We are evaluating the impact of this guidance on our consolidated financial statements.

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~


~~15.~~	~~Recently Issued Accounting Standards~~

In May 2014, the Financial Accounting Standards Board (FASB) issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the Company expects to receive in the exchange. In March 2016, the FASB issued an update clarifying the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued an update clarifying the identification of performance obligations and licensing implementations guidance. In May 2016, the FASB issued an update clarifying guidance in a few narrow areas and added some practical expedients to the guidance. In September 2017, the FASB issued an update clarifying the definition of a public business entity for the application of the new revenue recognition standards. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early application permitted after December 31, 2016. The standard is required to be adopted using either the full retrospective approach or the modified retrospective approach. While early adoption is permitted, we plan to adopt this new standard in the first quarter of 2018 using the modified retrospective approach. Through September 30, 2017, we have made progress on contract reviews, drafting accounting policies and evaluating the additional information required to be accumulated and analyzed to complete new disclosure requirements. We expect that enhanced disclosures will be required under the new standard. Further analysis is planned in the fourth quarter of ~~2017 to complete our evaluation~~2024, and the carbon sequestration portion of the ~~impact of~~project is subject to regulatory approvals. We have a 35% interest in the ~~new standard.~~

~~In February 2016, the FASB issued updated lease accounting guidance requiring companies to recognize the assets~~project and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018. In September 2017, the FASB issued an update clarifying the definition of a public business entity for the application of the new leasing standards. The standard will not apply tohave approximately $290 million remaining in our ~~leases of mineral rights. We are continuing to further evaluate the impact of this guidance on our consolidated financial statements and related disclosures.~~

~~In August 2017, the FASB issued derivatives and hedging guidance which makes significant changes~~commitment to the ~~current hedge accounting rules. The new guidance impacts~~project through the ~~designation~~end of ~~hedging relationships, measurement~~2024. We have accounted for this investment as an equity method investment, and its carrying value as of ~~hedging relationships, presentation~~March 31, 2023 and December 31, 2022 was $56 million and $18 million, respectively.

Contents

~~CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~


~~16.~~			~~Subsequent Events~~

On October 12, 2017, we issued in a private placement $300 million aggregate principal amount of 8.00% Senior Notes due 2025 (New 2025 Notes) at 101.25% of par, plus accrued interest from July 15, 2017, and $550 million aggregate principal amount of 8.00% Senior Notes due 2027 (New 2027 Notes) at 99.75% of par, plus accrued interest from June 6, 2017. The New 2025 Notes are an additional issuance of our outstanding 8.00% Senior Notes due 2025, which we issued in December 2016 in an original aggregate principal amount of $1.0 billion. The New 2025 Notes issued and the previously issued senior notes due 2025 will be treated as a single class of notes under the indenture. The New 2027 Notes are an additional issuance of our outstanding 8.00% Senior Notes due 2027, which we issued in June 2017 in an original aggregate principal amount of $750 million. The New 2027 Notes issued and the previously issued senior notes due 2027 will be treated as a single class of notes under the indenture. Aggregate net proceeds from the issuance of the New 2025 Notes and New 2027 Notes, excluding the accrued interest received, were approximately $842 million.

On October 13, 2017, we used a portion of the net proceeds from the offering discussed above to finance $550 million in tender offers for certain of our senior notes. We repurchased approximately $320 million principal amount of our 8.00% Senior Secured Second Lien Notes due 2022 for $350 million plus accrued and unpaid interest, approximately $136 million principal amount of our 6.625% Senior Notes due 2020 for $141 million plus accrued and unpaid interest, approximately $51 million principal amount of our 6.875% Senior Notes due 2020 for $53 million plus accrued and unpaid interest, approximately $3 million principal amount of our 6.125% Senior Notes due 2021 for $3 million plus accrued and unpaid interest and approximately $3 million principal amount of our 5.375% Senior Notes due 2021 for $3 million plus accrued and unpaid interest.

In addition, in October 2017, we used additional proceeds from the issuances described above to repurchase approximately $237 million principal amount of our secured term loan due 2021 for $258 million.

On October 30, 2017, the administrative agent under our senior revolving credit facility, in addition to other lenders under the agreement, notified us that the borrowing base had been reaffirmed at $3.8 billion.


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

~~Financial Data~~

The following table sets forth certain information regarding our production volumes, oil, natural gas and NGL sales, average sales prices received, and other operating income and expenses for the periods indicated:

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net Production:
Oil (mmbbl) 8
8
23
25
Natural gas (bcf) 219
268
639
814
NGL (mmbbl) 5
6
15
19
Oil equivalent (mmboe)^(a)
50
59
145
180
Average daily production (mboe) 542
638
532
656

Oil, Natural Gas and NGL Sales ($ in millions):
Oil sales $ 379
$ 342
$ 1,140
$ 952
Oil derivatives – realized gains (losses)^(b)
35
18
79
102
Oil derivatives – unrealized gains (losses)^(b)
(96 ) 23
45
(217 )
Total oil sales 318
383
1,264
837
Natural gas sales 553
622
1,807
1,545
Natural gas derivatives – realized gains (losses)^(b)
(1 ) (50 ) (53 ) 192
Natural gas derivatives – unrealized gains (losses)^(b)
(3 ) 131
384
(204 )
Total natural gas sales 549
703
2,138
1,533
NGL sales 117
84
328
247
NGL derivatives – realized gains (losses)^(b)
(3 ) (2 ) (1 ) (5 )
NGL derivatives – unrealized gains (losses)^(b)
(2 ) 9
(2 ) (2 )
Total NGL sales 112
91
325
240
Total oil, natural gas and NGL sales $ 979
$ 1,177
$ 3,727
$ 2,610

Average Sales Price
(excluding gains (losses) on derivatives):

Oil ($ per bbl) $ 47.94
$ 42.94
$ 48.53
$ 38.21
Natural gas ($ per mcf) $ 2.52
$ 2.32
$ 2.83
$ 1.90
NGL ($ per bbl) $ 21.83
$ 13.93
$ 21.28
$ 12.90
Oil equivalent ($ per boe) $ 21.06
$ 17.86
$ 22.53
$ 15.27

Average Sales Price
(including realized gains (losses) on derivatives):

Oil ($ per bbl) $ 52.33
$ 45.24
$ 51.90
$ 42.31
Natural gas ($ per mcf) $ 2.52
$ 2.13
$ 2.75
$ 2.13
NGL ($ per bbl) $ 21.26
$ 13.70
$ 21.21
$ 12.66
Oil equivalent ($ per boe) $ 21.67
$ 17.30
$ 22.70
$ 16.88

Other Operating Income ($ in millions):
Marketing, gathering and compression net margin^(c)(d)
$ (14 ) $ (162 ) $ (83 ) $ (169 )

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Expenses ($ per boe):
Oil, natural gas and NGL production $ 3.03
$ 2.80
$ 2.93
$ 3.07
Oil, natural gas and NGL gathering, processing and transportation $ 7.40
$ 8.07
$ 7.43
$ 7.99
Production taxes $ 0.43
$ 0.29
$ 0.44
$ 0.30
General and administrative $ 1.08
$ 1.08
$ 1.30
$ 0.96
Oil, natural gas and NGL depreciation, depletion and amortization $ 4.57
$ 4.26
$ 4.31
$ 4.40
Depreciation and amortization of other assets $ 0.41
$ 0.42
$ 0.43
$ 0.46
Interest expense^(e)
$ 2.26
$ 1.20
$ 2.05
$ 1.06

Interest Expense ($ in millions):
Interest expense $ 115
$ 74
$ 302
$ 199
Interest rate derivatives – realized (gains) losses^(f)
(1 ) (3 ) (3 ) (9 )
Interest rate derivatives – unrealized (gains) losses^(f)
—
2
3
7
Total interest expense $ 114
$ 73
$ 302
$ 197


~~(a)~~			~~Oil equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency.~~Introduction

~~(b)~~

Realized gains (losses) include the following items: (i) settlements and accruals for settlements of undesignated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains (losses) related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains (losses) include the change in fair value of open derivatives scheduled to settle against future period production revenues (including current period settlements for option premiums and early terminated derivatives) offset by amounts reclassified as realized gains (losses) during the period.


~~(c)~~	~~Includes revenue and operating costs. See~~ ~~Depreciation and Amortization of Other Assets~~ ~~under~~ ~~Results of Operations~~ ~~for details of the depreciation and amortization associated with our marketing, gathering and compression segment.~~

~~(d)~~

In the Prior Quarter and the Prior Period, we recorded unrealized losses of $280 million and $297 million, respectively, on the fair value of our supply contract derivative. Additionally, in the Prior Quarter, we sold the supply contract to a third party for cash proceeds of $146 million. See Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for discussion related to this instrument.


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

~~(f)~~

Realized (gains) losses include interest rate derivative settlements related to current period interest and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. Unrealized (gains) losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.

~~Overview~~This Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to provide a reader of our financial statements with management’s perspective on our financial condition, liquidity, results of operations and certain other factors that may affect our future results. The following discussion should be read together with the condensed consolidated financial statements included in Item 1 of Part I of this report and the consolidated financial statements included in Item 8 of our 202 2 Form 10-K.

We ~~own interests~~are an independent exploration and production company engaged in ~~approximately 17,100~~the acquisition, exploration and development of properties to produce natural gas, oil and ~~natural gas wells and produced an average of approximately 542 mboe per day in the Current Quarter, net to our interest.~~NGL from underground reservoirs. We ~~have~~own a large ~~and geographically diverse resource base~~portfolio of onshore U.S. unconventional natural gas and liquids ~~assets. We have leading positions~~assets, including interests in ~~the liquids-rich resource plays~~approximately 7,200 natural gas and oil wells as of ~~the Eagle Ford Shale in South Texas, the Anadarko Basin in northwestern Oklahoma and the stacked pay in the Powder River Basin in Wyoming.~~March 31, 2023. Our natural gas resource plays are ~~the Haynesville/Bossier Shales in northwestern Louisiana and East Texas, the Utica Shale in Ohio and~~ the Marcellus Shale in the northern Appalachian Basin in ~~Pennsylvania. We also own oil~~Pennsylvania (“Marcellus”) and ~~natural gas marketing~~the Haynesville/Bossier Shales in northwestern Louisiana (“Haynesville”). Our liquids-rich resource play is in the Eagle Ford Shale in South Texas (“Eagle Ford”). In August 2022, we announced that we viewed the assets in Eagle Ford as non-core to our future capital allocation strategy. In January 2023, we entered into an agreement to sell a portion of our Eagle Ford assets to WildFire Energy I LLC for $1.425 billion and ~~natural gas compression businesses.~~closed the transaction on March 20, 2023. Additionally, in February 2023, we entered into an agreement to sell a portion of our remaining Eagle Ford assets to INEOS Energy for $1.4 billion and closed the transaction on April 28, 2023.

Our ~~Strategy~~

~~Chesapeake’s~~ strategy is to create shareholder value through the responsible development of our significant ~~positions in premier U.S. onshore~~ resource ~~plays. In addition, we~~plays while continuing to be a leading provider of affordable, reliable, low carbon energy to the United States. We continue to focus ~~our~~on improving margins through operating efficiencies and financial ~~strategy on reducing debt~~discipline and improving ~~margins~~our ESG performance. To accomplish these goals, we intend to allocate our human resources and returns on capital. We apply financial discipline to all aspects of our business with goals of increasing financial and operational flexibility. Our capital program is focused on investments that can improve our cash flow generating ability regardless of the commodity price environment. Our forecasted capital expenditures ~~are higher in 2017 compared~~ to ~~2016 as~~projects we ~~focus~~believe offer the highest cash return on ~~capturing high rate-of-return~~capital invested, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities into strengthen our ~~oil and natural gas~~ portfolio. ~~These opportunities are primarily the result of improved capital and operating efficiencies, including improved well performance.~~ We expect our anticipated production increases in the 2017 fourth quarter, combined with our cost leadership and discipline, will position us with the ability to balance capital expenditures and operating cash flow in 2018.

Our substantial inventory of hydrocarbon resources, including our significant undeveloped acreage position in each of our key basins, provides a strong foundation to create future value. Concentrated blocks of undeveloped acreage give us the opportunity to apply best in class well spacing analysis, completion techniques and lateral lengths to maximize capital efficiency. We have greatly improved our capital and operating efficiency metrics over the last several periods and today have a leading cost structure in each of our major operating basins. We believe our cost structure provides a significant competitive advantage in the current commodity price environment and it is our strategyalso intend to continue to ~~seek~~dedicate capital ~~and operating efficiencies~~ to ~~grow this advantage. Building on our strong and diverse asset base and further delineating our emerging new development opportunities, we believe~~projects that ~~our dedication to financial discipline,~~reduce the ~~flexibility and efficiency~~environmental impact of our ~~capital program~~natural gas and ~~cost structure and our continued focus on safety and environmental stewardship will provide~~oil producing activities. We continue to seek opportunities to ~~create value~~reduce cash costs (production, gathering, processing and transportation and general and administrative), through operational efficiencies and improving our production volumes from existing wells.

Leading a responsible energy future is foundational to Chesapeake's success. Our core values and culture demand we continuously evaluate the environmental impact of our operations and work diligently to improve our ESG performance across all facets of our Company. Our path to answering the call for usaffordable, reliable, low carbon energy begins with our goal to achieve net zero greenhouse gas emissions (Scope 1 and 2) by 2035. To meet this challenge, we have set meaningful goals including:

•Eliminate routine flaring from all new wells completed from 2021 forward, and enterprise-wide by 2025;

•Reduce our ~~stakeholders.~~methane intensity to 0.02% by 2025 (achieved approximately 0.05% in 2022); and

~~Operating Results~~

~~Our Current Quarter production of 50 mmboe consisted of 8 mmbbls~~•Reduce our GHG intensity to 3.0 metric tons CO2 equivalent per thousand barrel of oil ~~(16% on an oil~~ equivalent ~~basis), 219 bcf~~by 2025 (achieved approximately 3.9 in 2022).

In July 2021, we announced our plan to receive independent certification of our natural gas production under the MiQ methane standard and EO100™ Standard for Responsible Energy Development. By the end of 2022, we had received certifications for all our operated gas assets in Haynesville and Marcellus as responsibly sourced gas. The MiQ certification provides a verified approach to tracking our commitment to reduce our methane intensity, as well as supporting our overall objective of achieving net-zero Scope 1 and 2 greenhouse gas emissions by 2035.

As the majority of our production profile consists of natural gas, ~~(73% on an~~we have converted the following results of operations, including prior periods, from a per barrel of oil equivalent, ~~basis), and 5 mmbbls~~to a per one thousand cubic feet of NGL (11% on an oil equivalent basis). Our daily production for the Current Quarter averaged approximately 542 mboe, a decrease of 15% from the Prior Quarter. Compared to the Prior Quarter, average daily oil production decreased by 1%, or approximately 1 mbbl per day; average daily natural gas ~~production decreased by 18%, or approximately 532 mmcf per day;~~equivalent, referred to, on such a converted basis, as Mcfe.


Recent Developments

Acquisition

On March 9, 2022, we closed our Marcellus Acquisition pursuant to definitive agreements with Chief, Radler and ~~average daily NGL production decreased by 11%, or approximately 7 mbbls per day. Our oil, natural gas~~Tug Hill, Inc. dated January 24, 2022. This transaction strengthened Chesapeake’s competitive position, meaningfully increasing our operating cash flows and ~~NGL production decreased primarily as~~adding high quality producing assets and a ~~result~~deep inventory of premium drilling locations, while preserving the strength of our balance sheet.

Divestitures

On March 25, 2022, we closed the sale of ~~certain of~~ our ~~Mid-Continent and Barnett Shale~~Powder River Basin assets in ~~2016 and the sale of certain of our Haynesville Shale assets~~Wyoming to Continental Resources, Inc. for $450 million in ~~2017. Adjusted for asset sales, our total daily production was approximately unchanged~~cash, subject to post-closing adjustments, which resulted in the Current Quarter compared to the Prior Quarter. Our oil, natural gas and NGL total revenues (excluding gains or losses on oil and natural gas derivatives) were approximately unchanged in the Current Quarter compared to the Prior Quarter, due to increases in the prices received for oil, natural gas and NGL sold, offset by the production decreases described above. See ~~Results~~recognition of ~~Operations~~ ~~below for additional details.~~

Our Current Period production of 145 mmboe consisted of 23 mmbbls of oil (16% on an oil equivalent basis), 639 bcf of natural gas (73% on an oil equivalent basis), and 15 mmbbls of NGL (11% on an oil equivalent basis). Our daily production for the Current Period averaged approximately 532 mboe, a decrease of 19% from the Prior Period. Compared to the Prior Period, average daily oil production decreased by 5%, or approximately 5 mbbls per day; average daily natural gas production decreased by 21%, or approximately 630 mmcf per day; and average daily NGL production decreased by 19%, or approximately 13 mbbls per day. Our oil, natural gas and NGL production decreased primarily as a result of the sale of certain of our Mid-Continent and all of our Barnett Shale assets in 2016 and the sale of certain of our Haynesville Shale assets in 2017. Adjusted for asset sales, our total daily production decreased 2% in the Current Period compared to the Prior Period. Our oil, natural gas and NGL total revenues (excluding gains or losses on oil and natural gas derivatives) increased approximately $531 million to $3.275 billion in the Current Period compared to $2.744 billion in the Prior Period, due to increases in the prices received for oil, natural gas and NGL sold, partially offset by the production decreases described above. See ~~Results of Operations~~ ~~below for additional details.~~

~~Capital Expenditures~~

Our drilling and completion capital expenditures during the Current Quarter were approximately $626 million and capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment were approximately $17 million, for a totalgain of approximately ~~$643~~$293 million. In the Current Quarter, we operated an average of 17 rigs, an increase of six rigs, or 55%, compared to the Prior Quarter. As a result of higher drilling and completion activity as well as higher service and supply costs, drilling and completion expenditures increased approximately $294 million in the Current Quarter compared to the Prior Quarter. Capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment decreased approximately $4 million compared to the Prior Quarter.

Our capitalized interest was approximately $49 million and $59 million in the Current Quarter and the Prior Quarter, respectively. The decrease in capitalized interest resulted from a lower average balance of our unproved oil and natural gas properties, the primary asset on which interest is capitalized. Including capitalized interest, total capital investments were approximately $692 million in the Current Quarter compared to $412 million for the Prior Quarter, an increase of 68%.

Our drilling and completion capital expenditures during the Current Period were approximately $1.728 billion and capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment were approximately $60 million, for a total of approximately $1.788 billion. In the Current Period, we operated an average of 18 rigs, an increase of eight rigs, or 80%, compared to the Prior Period. As a result of higher drilling and completion activity as well as higher service and supply costs, drilling and completion expenditures increased approximately $777 million in the Current Period compared to the Prior Period. Capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment decreased approximately $31 million compared to the Prior Period.

Our capitalized interest was approximately $147 million and $191 million in the Current Period and the Prior Period, respectively. The decrease in capitalized interest resulted from a lower average balance of our unproved oil and natural gas properties, the primary asset on which interest is capitalized. Including capitalized interest, total capital investments were approximately $1.935 billion in the Current Period compared to $1.233 billion for the Prior Period, an increase of 57%.

Based on planned activity levels for the remainder of 2017, we project that 2017 capital expenditures for drilling and completions, leasehold, geological and geophysical and other property and equipment will be $2.3 – $2.5 billion, inclusive of capitalized interest, as compared to $1.7 billion of capital expenditures in 2016. See ~~Liquidity and Capital Resources~~ ~~for additional information on how we plan to fund our capital budget.~~

~~Strategic Developments~~

~~Debt Offerings~~

On ~~October 12, 2017,~~January 17, 2023, we issued in a private placement $300 million aggregate principal amount of 8.00% Senior Notes due 2025 (New 2025 Notes) at 101.25% of par, plus accrued interest from July 15, 2017, and $550 million aggregate principal amount of 8.00% Senior Notes due 2027 (New 2027 Notes) at 99.75% of par, plus accrued interest from June 6, 2017. Aggregate net proceeds from the issuance of the New 2025 Notes and New 2027 Notes, excluding the accrued interest received, were approximately $842 million. See Note 16 of the notesentered into an agreement to ~~our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion.~~

~~In the Current Period, we issued $750 million aggregate principal amount of unsecured 8.00% Senior Notes due 2027 in a private placement for net proceeds of $742 million.~~

~~Debt Retirements~~

On October 13, 2017, we used a portion of the net proceeds from the offering discussed above to finance $550 million in tender offers for certain of our senior notes. We repurchased approximately $320 million principal amount of our 8.00% Senior Secured Second Lien Notes due 2022 for $350 million plus accrued and unpaid interest, and approximately $193 million principal amount of various series of our senior notes due 2020 and 2021 for $200 million plus accrued and unpaid interest. See Note 16 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion.

~~In addition, we used additional proceeds from the October issuances described above to repurchase approximately $237 million principal amount of our secured term loan due 2021 for $258 million.~~

In the Current Period, we retired $1.609 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $1.751 billion. Retirements included (i) the maturity of our 6.25% Euro-denominated Senior Notes due 2017 and corresponding cross currency swap, (ii) our tender offer for our 2.5% Contingent Convertible Senior Notes due 2037 at the option of the holders of the notes pursuant to the terms of the notes, (iii) our tender offer forsell a portion of our ~~senior secured second lien notes, (iv)~~Eagle Ford assets to WildFire Energy I LLC for $1.425 billion, subject to post-closing adjustments. This transaction closed on March 20, 2023 and resulted in the ~~repurchase~~recognition of ~~our 6.5% Senior Notes due 2017, and (v) the repurchases~~a gain of approximately $335 million.

On February 17, 2023, we entered into an agreement to sell a portion of our remaining ~~2.75% Contingent Convertible Senior Notes due 2035~~Eagle Ford assets to INEOS Energy for $1.4 billion, subject to post-closing adjustments. This transaction closed on April 28, 2023, and ~~2.5% Contingent Convertible Senior Notes due 2037.~~we received proceeds of approximately $1.055 billion. As of March 31, 2023, the assets and liabilities associated with this transaction were classified as held for sale.

~~Preferred Stock Exchanges~~Investments - Momentum Sustainable Ventures LLC

During the fourth quarter of 2022, we entered into an agreement with Momentum Sustainable Ventures LLC to build a new natural gas gathering pipeline and carbon capture and sequestration project, which will gather natural gas produced in the Haynesville Shale for re-delivery to Gulf Coast markets, including LNG export. The pipeline is expected to have an initial capacity of 1.7 Bcf/d expandable to 2.2 Bcf/d. The carbon capture portion of the project anticipates capturing and permanently sequestering up to 2.0 million tons per annum of CO2. The natural gas gathering pipeline in-service is projected for the fourth quarter of 2024, and the carbon sequestration portion of the project is subject to regulatory approvals. Through the end of the first quarter of 2023, we have made total capital contributions of $56 million to the project.

Repurchases of Equity Securities and Dividends

In June 2022, our Board of Directors authorized an increase in the ~~Current Period,~~size of our share repurchase program from $1.0 billion to up to $2.0 billion in aggregate value of our common stock and/or warrants. During the three months ended March 31, 2023, we ~~completed private exchanges of an aggregate of~~repurchased approximately ~~10.0~~0.8 million shares of our common stock ~~for (i) 72,600 shares~~pursuant to the share repurchase program and had $867 million available under the share repurchase program, as of ~~5.75% Cumulative Convertible Preferred Stock, (ii) 12,500 shares~~March 31, 2023. In addition, we paid dividends of ~~5.75% Cumulative Convertible Preferred Stock (Series A)~~approximately $175 million, in aggregate, on our common stock during the three months ended March 31, 2023.

Russia’s Invasion of Ukraine; Volatility in Natural Gas, Oil and (iii) 150,948 shares of 5.00% Cumulative Convertible Preferred Stock (Series 2005B). The preferred stock exchanged represents approximately $100 million of liquidation value. These exchanges eliminated approximately $6 million of annual dividend obligations.NGL Prices; Inflationary Cost Pressures and Potential Economic Downturns

~~Divestitures~~

In late February 2022, Russia launched a military invasion against Ukraine. The Russian invasion has caused, and could intensify, volatility in natural gas, oil and NGL prices, and may have an impact on global growth prospects, which could in turn affect demand for natural gas and oil. This overall uncertainty resulted in stronger commodity prices during much of 2022. Toward the ~~Current Period, we sold portions~~end of 2022, markets began to stabilize, and this, coupled with a milder winter, has resulted in an observed decline in pricing in early 2023. Our 2023 estimated cash flow is partially protected from commodity price volatility due to our current hedge positions that cover approximately 55% to 65% of our ~~acreage~~projected natural gas volumes for the remainder of 2023.

In addition to the recent weakening in commodity prices, the industry is experiencing inflationary pressure, including increased demand for oilfield service equipment, rising fuel costs, and ~~producing properties~~labor shortages, which could result in increases to our operating and capital costs that are not fixed. Uncertainty regarding a potential economic

downturn or recession in certain regions, or globally, may introduce new pressures or accelerate or intensify the pressures currently facing the industry. We continue to monitor these situations and assess their impact on our business, including our business partners and customers. For additional discussion regarding risks associated with price volatility and economic deterioration, see Part I, Item 1A “Risk Factors” in our ~~Haynesville Shale operating area~~2022 Form 10-K.

COVID-19 Pandemic and Impact on Global Demand for Natural Gas and Oil

The global spread of COVID-19 created significant volatility, uncertainty, and economic disruption commencing in ~~northern Louisiana for approximately $915 million, subject~~2020, and threatens to ~~certain customary closing adjustments. Included~~continue to do so in 2023. While we cannot predict the full impact that COVID-19 and its variants, or the related disruption and volatility in the ~~sales were approximately 119,500 net acres~~natural gas and ~~interests in 576 wells that were producing approximately 80 mmcf~~oil markets may have on our business, cash flows, liquidity, financial condition and results of ~~gas per day at~~operations, we believe our cost structure and liquidity position us well to address continued price and demand volatility. For additional discussion regarding risks and impacts associated with the ~~time of closing.~~

~~Also in the Current Period, we have signed or closed approximately $360 million of additional asset divestitures, primarily~~COVID-19 pandemic, see Part I, Item 1A “Risk Factors” in our ~~Mid-Continent area.~~2022 Form 10-K.

~~Gathering, Processing and Transportation Agreements~~

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


Liquidity and Capital Resources

Liquidity Overview

Our ~~ability to grow, make~~primary sources of capital ~~expenditures~~resources and ~~service~~liquidity are internally generated cash flows from operations and borrowings under our ~~debt depends primarily upon the prices we receive~~credit agreements, and our primary uses of cash are for the ~~oil,~~development of our natural gas and ~~NGL we sell. Substantial expenditures are required to replace reserves, sustain production and fund our business plans. Historically,~~ oil ~~and~~properties, acquisitions of additional natural gas ~~prices have been very volatile,~~properties and ~~may be subject~~return of value to ~~wide fluctuations in~~stockholders through dividends and equity repurchases. We believe our cash flow from operations, proceeds from our recent Eagle Ford divestitures, cash on hand and borrowing capacity under the New Credit Facility, as discussed below, will provide sufficient liquidity during the next 12 months and the foreseeable future. ~~The substantial decline in oil, natural gas and NGL prices from 2014 levels has negatively affected the amount~~As of March 31, 2023, we had $2.1 billion of liquidity available, including $130 million of cash ~~we generate~~on hand and ~~have available for capital expenditures and debt service. A substantial or extended decline in oil, natural gas and NGL prices could have a material impact on our financial position, results~~$2.0 billion of operations, cash flows and on the quantities of reserves that we may economically produce. Other risks and uncertainties that could affect our liquidity include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks and our ability to meet financial ratios and covenants in our financing agreements and the size of lenders’ commitments as a result of regulatory pressures in the lending market.

As of September 30, 2017, we had a cash balance of $5 million compared to $882 million as of December 31, 2016, and we had a net working capital deficit of $1.040 billion, compared to a net working capital deficit of $1.506 billion as of December 31, 2016. As of September 30, 2017, we had $3.043 billion ofaggregate unused borrowing capacity available under ~~our revolving credit facility, with~~the New Credit Facility. As of March 31, 2023, we had no outstanding borrowings ~~of $645 million and $97 million utilized for various letters of credit. Based on our cash balance, forecasted cash flows from operating activities and availability~~ under our ~~revolving credit facility, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.~~New Credit Facility. See Note 3 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of our debt obligations, including ~~principal~~the carrying and ~~carrying amounts of our notes.~~

~~Through November 1, 2017, we have taken the following measures to improve our near-term liquidity:~~

~~issued $300 million aggregate principal amount of 8.00% Senior Notes due 2025 and $1.3 billion aggregate principal amount of 8.00% Senior Notes due 2027 and used the proceeds to repurchase a portion~~fair value of our senior ~~secured second lien notes, a portion~~notes.

Dividends

We paid dividends of ~~our senior notes due in 2020 and 2021 and a portion of our term loan due 2021;~~

~~reaffirmed the borrowing base~~$175 million on ~~our revolving credit facility at $3.8 billion;~~

exchanged approximately 10.0 million shares of common stock for approximately $100 million of liquidation value of our preferred stock, eliminating approximately $6 million of annual dividend obligations;

~~completed approximately $1.3 billion of asset divestitures that did not fit our strategic priorities; and~~

~~protected a significant amount of 2018 cash flow through hedging activities discussed below.~~

Even though we have taken measures, as outlined above, to mitigate the liquidity concerns facing us for the next 12 months, there can be no assurance that these measures will satisfy our needs. We may continue to access the capital markets or otherwise incur debt to refinance a portion of our outstanding indebtedness and improve our liquidity.

As operator of a substantial portion of our oil and natural gas properties under development, we have significant control and flexibility over the timing and execution of our development plan, enabling us to reduce our capital spending as needed. Our forecasted 2017 capital expenditures, inclusive of capitalized interest, are $2.3 – $2.5 billion compared to our 2016 capital spending level of $1.7 billion. We had liquidity (calculated as cash on hand and availability under our revolving credit facility), of approximately $3.1 billion as of October 31, 2017. We expect to generate additional liquidity with proceeds from future sales of assets that do not fit our strategic priorities. Management continues to review operational plans for the remainder of 2017 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL. We closely monitor the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our revolving credit facility.

Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as gathering, processing, transportation and hedging agreements. As of October 31, 2017, we have received requests and posted approximately $130 million of collateral related to certain of our marketing and other contracts and $1 million of collateral related to certain of our derivative contracts. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $487 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business relationships with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business arrangements and by offsetting amounts that the counterparty owes us. Any posting of collateral consisting of cash or letters of credit reduces availability under our revolving credit facility and negatively impacts our liquidity.

~~In the Current Period, we completed several debt and equity transactions, as described above, to improve our balance sheet. We may continue to use a combination of cash, borrowings and issuances of~~ our common stock or other securities to retire our outstanding debt and preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.

~~To add more certainty to our future estimated cash flows by mitigating our downside exposure to lower commodity prices, as~~during the first three months of October 31, 2017, we have downside price protection, through open swaps, on approximately 62% of our remaining projected 2017 oil production at an average price of $50.36 per bbl. We also have downside price protection, through open swaps and collars, on approximately 83% of our remaining projected 2017 natural gas production at an average price of $3.17 per mcf, of which 11% is hedged under two-way collar arrangements based on an average bought put NYMEX price of $3.25 per mcf. We also have downside price protection, through open swaps, on a portion of our projected propane revenue at an average price of $0.76 per gallon, representing approximately 8% of our remaining projected 2017 NGL production. In addition, we have downside price protection, through open swaps on 19 mmbbls of our 2018 oil production at an average price of $51.74 per bbl and under three-way collar arrangements on 2 mmbbls based on an average bought put NYMEX price of $47 per bbl and exposure below an average sold put NYMEX price of $39.15 per bbl. We also have downside price protection, through open swaps and collars on 579 bcf of our 2018 natural gas production at an average price of $3.10 per mcf, of which 47 bcf is hedged under two-way collar arrangements based on an average bought put NYMEX price of $3.00 per mcf. We also have downside price protection, through open swaps, on approximately 0.6 mmbbls of projected 2018 NGL production at an average price of $0.73 per gallon. We also have hedged a portion of oil production sold under LLS contracts at the Gulf Coast and northeast natural gas production sold in-basin through the use of basis swaps.

As highlighted above, we have taken measures to mitigate the liquidity concerns facing us for the remainder of 2017 and beyond, but there can be no assurance that such measures will satisfy our needs. Further, our ability to generate operating cash flow in the current commodity price environment, sell assets, access capital markets or take any other action to improve our liquidity and manage our debt is subject to the risks discussed above and the other risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time or control.

~~Sources of Funds~~

~~The following table presents the sources of our cash and cash equivalents for the Current Period and the Prior Period.~~2023. See Note 9 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further ~~discussion~~discussion.

On May 2, 2023, we declared a quarterly dividend payable of ~~divestitures~~$1.18 per share, which will be paid on June 6, 2023 to stockholders of record at the close of business on May 18, 2023. The dividend consists of a base quarterly dividend in the amount of $0.55 per share and a variable quarterly dividend in the amount of $0.63 per share.

The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of the Board and will depend on the Company’s financial results, cash requirements, future prospects and other relevant factors. The Company’s ability to pay dividends to its stockholders is restricted by (i) Oklahoma corporate law, (ii) its Certificate of Incorporation, (iii) the terms and provisions of the credit agreement governing its New Credit Facility and (iv) the terms and provisions of the indentures governing its 5.50% Senior Notes due 2026, 5.875% Senior Notes due 2029 and 6.75% Senior Notes due 2029.

Derivative and Hedging Activities

Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. We enter into various derivative instruments to mitigate a portion of our exposure to commodity price declines, but these transactions may also limit our cash flows in periods of rising commodity prices. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to better predict the total revenue we expect to receive. See Item 3. Quantitative and Qualitative Disclosures About Market Risk included in Part I of this report for further discussion on the impact of commodity price risk on our financial position.

Contractual Obligations and Off-Balance Sheet Arrangements

As of March 31, 2023, our material contractual obligations include repayment of senior notes, derivative obligations, asset retirement obligations, lease obligations, capital commitments relating to our investments,

undrawn letters of credit and various other commitments we enter into in the ordinary course of business that could result in future cash obligations. In addition, we have contractual commitments with midstream companies and pipeline carriers for future gathering, processing and transportation of natural gas, oil and NGL to move certain of our production to market. The estimated gross undiscounted future commitments under these agreements were approximately $4.2 billion as of March 31, 2023. As discussed above, we believe our existing sources of liquidity will be sufficient to fund our near and long-term contractual obligations. See Notes 4, 5, 1 1 and 12 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion.

New Credit Facility

On December 9, 2022, the Company, as borrower, entered into a senior secured reserve-based credit agreement providing for the New Credit Facility which features an initial borrowing base of $3.5 billion and aggregate commitments of $2.0 billion. Subject to certain exceptions, the borrowing base will be redetermined semi-annually in or around April and October of each year. The New Credit Facility provides for a $200 million sublimit available for the issuance of letters of credit and a $50 million sublimit available for swingline loans. Borrowings under the credit agreement may be alternate base rate loans or term SOFR loans, at the Company’s election. The New Credit Facility contains certain features that, upon receipt and maintenance of investment grade ratings from S&P, Moody’s and/or Fitch and the satisfaction of certain other conditions, result in the removal or relaxation of specified negative and financial covenants, among other favorable adjustments. See Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion.

Capital Expenditures

For the year ending December 31, 2023, we currently expect to bring or have online approximately 145 to 165 gross wells across 10 to 12 rigs and plan to invest between approximately $1.765 – $1.835 billion in capital expenditures. We expect that approximately 85% of our 2023 capital expenditures will be directed toward our natural gas assets. We currently plan to fund our 2023 capital program through cash on hand, expected cash flow from our operations and borrowings under our New Credit Facility. We may alter or change our plans with respect to our capital program and expected capital expenditures based on developments in our business, our financial position, our industry, or any of the markets in which we operate.

Nine Months Ended
September 30,
2017 2016
($ in millions)
Cash provided by operating activities $ 273
$ 50
Proceeds from credit facility borrowings, net 645
240
Proceeds from issuance of term loan —
1,500
Proceeds from issuance of senior notes, net 742
—
Divestitures of proved and unproved properties 1,193
988
Sales of other property and equipment 40
70
Total sources of cash and cash equivalents $ 2,893
$ 2,848
Sources and (Uses) of Cash and Cash Equivalents

The following table presents the sources and uses of our cash and cash equivalents for the periods presented:


	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022
Cash provided by operating activities	$	889	$	853
Proceeds from divestitures of property and equipment	931		403

Proceeds from Exit Credit Facility, net	—		500

Proceeds from warrant exercise	—		1
Capital expenditures	(497)		(344)
Business combination, net	—		(2,006)
Contributions to investments	(39)		—
Payments on New Credit Facility, net	(1,050)		—


Cash paid to repurchase and retire common stock	(54)		(83)
Cash paid for common stock dividends	(175)		(210)
Net increase (decrease) in cash, cash equivalents and restricted cash	$	5	$	(886)

Cash Flow from Operating Activities

Cash provided by operating activities was ~~$273~~$889 million inand $853 million during the ~~Current Period compared to $50 million in the Prior Period.~~first three months of 2023 and 2022, respectively. The increase during the first three months of 2023 is primarily due to increased sales volumes in Marcellus primarily due to the ~~result~~Marcellus Acquisition and timing of ~~higher realized prices for the oil, natural gas and NGL we sold,~~cash receipts, partially offset by lower ~~volumes of oil,~~prices for the natural gas, oil and NGL ~~sold, the payment related to the litigation on our 6.775% Senior Notes due 2019 and payments for terminations of transportation contracts. Changes in cash flow~~we sold. Cash flows from operations are largely ~~due to~~affected by the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of ~~fixed~~ assets, deferred income taxes and mark-to-market changes in our open derivative instruments. See further discussion below under Results of Operations.

~~We currently plan to use cash flow~~Proceeds from ~~operations, cash on hand~~Divestitures of Property and ~~our revolving credit facility to fund our capital expenditures for~~Equipment

During the ~~remainder~~first three months of ~~2017. We expect to generate additional liquidity with proceeds from future sales of assets that do not fit our strategic priorities. Under our revolving credit facilities,~~2023, we ~~borrowed $4.775 billion and repaid $4.130 billion in the Current Period, and we borrowed $5.097 billion and repaid $4.857 billion in the Prior Period.~~

~~Uses of Funds~~

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

Nine Months Ended
September 30,
2017 2016
($ in millions)
Oil and Natural Gas Expenditures:
Drilling and completion costs $ 1,597
$ 946
Acquisitions of proved and unproved properties 87
406
Interest capitalized on unproved leasehold 139
179
Total oil and natural gas expenditures 1,823
1,531
Other Uses of Cash and Cash Equivalents:
Cash paid to repurchase debt 1,751
1,979
Cash paid for title defects —
69
Additions to other property and equipment 12
32
Dividends paid 160
—
Other 24
58
Total other uses of cash and cash equivalents 1,947
2,138
Total uses of cash and cash equivalents $ 3,770
$ 3,669

~~Our drilling and completion costs increased in the Current Period compared~~Eagle Ford assets to ~~the Prior Period primarily as a result of increased activity as well as higher service and supply costs.~~WildFire Energy I LLC. During the ~~Current Period,~~first three months of 2022, we sold our ~~average operated rig count was 18 rigs compared~~Powder River Basin assets to ~~an average operated rig count of ten rigs in the Prior Period and we completed 326 operated wells in the Current Period compared to 280 in the Prior Period.~~

In the Current Period, we used $1.751 billion of cash to repurchase $1.609 billion principal amount of debt. In the Prior Period, we used $1.979 billion of cash to repurchase $2.192 billion principal amount of debt.

We paid dividends of $160 million on our preferred stock during the Current Period, including $92 million of dividends in arrears that had been suspended throughout 2016. We did not pay dividends on our preferred stock in the Prior Period.

Continental Resources, Inc. See ~~TABLE OF CONTENTS~~

~~Term Loan Facility~~

~~We have a secured five-year term loan facility in an aggregate principal amount of $1.5 billion as of September 30, 2017. As discussed in~~ Note 16 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report, in October 2017, we repurchased $237 million principal amount of the outstanding balance. Our obligations under the facility are unconditionally guaranteed on a joint and several basis by the same subsidiaries that guarantee our revolving credit facility, second lien notes and senior notes, and are secured by first-priority liens on the same collateral securing our revolving credit facility (with a position in the collateral proceeds waterfall junior to the revolving credit facility). The term loan bears interest at a rate of London Interbank Offered Rate (LIBOR) plus 7.50% per annum, subject to a 1.00% LIBOR floor, or the Alternative Base Rate (ABR) plus 6.50% per annum, subject to a 2.00% ABR floor, at our option. The term loan matures in August 2021 and voluntary prepayments are subject to a make-whole premium prior to the second anniversary of the closing of the term loan, a premium to par of 4.25% from the second anniversary until but excluding the third anniversary, a premium to par of 2.125% from the third anniversary until but excluding the fourth anniversary and at par beginning on the fourth anniversary. The term loan may be subject to mandatory prepayments and offers to purchase with net cash proceeds of certain issuances of debt, certain asset sales and other dispositions of collateral and upon a change of control. See Note 32 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further ~~discussion~~discussion.

Proceeds from Exit Credit Facility, net

During the first three months of 2022, we borrowed a net $500 million on the Exit Credit Facility to fund a portion of the ~~term loan facility.~~Marcellus Acquisition.

~~Revolving Credit Facility~~Capital Expenditures

~~We have~~Our capital expenditures increased during the first three months of 2023 compared to the first three months of 2022, primarily as a ~~senior secured revolving credit facility currently subject to a $3.8~~result of increased drilling and completion activity across all operating areas, as well as inflation-related cost increases for goods and services.

Business Combination

During the first three months of 2022, we closed the Marcellus Acquisition for approximately $2 billion ~~borrowing base that matures in December 2019. As of September 30, 2017, we had outstanding borrowings of $645~~ and 9.4 million ~~under the revolving credit facility and had used $97 million of the revolving credit facility for various letters of credit. See~~ ~~Liquidity Overview~~ above for additional information on our collateral postings. Borrowings under the facility bear interest at a variable rate. We are required to secure our obligations under the facility with liens on certain shares of our oil and natural gas properties, with the liens to be released upon the satisfaction of specific conditions. The applicable interest rates under the facility fluctuate based on the percentage of the borrowing base used. On October 30, 2017, our borrowing base was reaffirmed at $3.8 billion. Our next borrowing base redetermination is scheduled for the second quarter of 2018.common stock. See Note 3 2 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further ~~discussion~~discussion.

Contributions to Investments

During the first three months of ~~the terms of the revolving credit facility, as amended. As of September 30, 2017, our first lien secured leverage ratio was approximately 0.72~~2023, contributions to ~~1.00 and our interest coverage ratio was approximately 1.50 to 1.00, and we were in compliance with all applicable financial covenants under the credit agreement.~~

~~Hedging Arrangements~~

Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under our revolving credit facility. The contracts entered into with these counterparties are secured by the same collateral that secures our revolving credit facility which allows us to reduce any letters of credit posted as security with those counterparties. In addition, we enter into bilateral hedging agreements with other counterparties. The counterparties’ and our obligations under the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds.

~~Senior Note Obligations~~

~~Our senior note obligations~~investments primarily consisted of ~~the following as of September 30, 2017:~~

September 30, 2017
Principal
Amount Carrying
Amount
($ in millions)
7.25% senior notes due 2018 $ 44
$ 44
Floating rate senior notes due 2019 380
380
6.625% senior notes due 2020 572
572
6.875% senior notes due 2020 279
278
6.125% senior notes due 2021 550
550
5.375% senior notes due 2021 270
270
4.875% senior notes due 2022 451
451
8.00% senior secured second lien notes due 2022^(a)
1,737
2,355
5.75% senior notes due 2023 338
338
8.00% senior notes due 2025 1,000
987
5.5% convertible senior notes due 2026^(b)(c)
1,250
831
8.00% senior notes due 2027 750
750
2.25% contingent convertible senior notes due 2038^(c)(d)
9
8
Debt issuance costs —
(42 )
Interest rate derivatives^(e)
—
2
Total long-term senior notes, net^(f)
$ 7,630
$ 7,774


~~(a)~~	~~The carrying amount as of September 30, 2017, includes a premium of $618 million associated with a troubled debt restructuring. The premium is being amortized based on an effective yield method.~~


~~(b)~~	The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash, common stock or a combination of cash and common stock, at our election. The holders of our convertible senior notes may require us to repurchase the principal amount of the notes upon certain fundamental changes.


~~(c)~~	~~The carrying amount as of September 30, 2017, is reflected net of a discount associated with the equity component of our convertible and contingent convertible senior notes of $420 million.~~

~~(d)~~

The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process. The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date and upon certain fundamental changes.


~~(e)~~	~~See Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for discussion related to these instruments.~~


~~(f)~~	~~See Note 16 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for information regarding debt transactions subsequent to September 30, 2017.~~

~~For further discussion and details regarding our senior notes and convertible senior notes, see Note 3 of the notes~~$39 million, which we contributed to our ~~condensed consolidated financial statements included in Item 1 of Part I of this report.~~

~~Credit Risk~~

~~Derivative instruments that enable us~~investment with Momentum Sustainable Ventures LLC to ~~manage our exposure to oil,~~build a new natural gas gathering pipeline and NGL prices expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with counterparties that are highly rated or deemed by the Company 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 September 30, 2017, our oil, natural gas and NGL derivative instruments were spread among 10 counterparties. Additionally, the counterparties under our commodity hedging arrangements are required to secure their obligations in excess of defined thresholds.

Our accounts receivable are primarily from purchasers of oil, natural gas and NGL ($721 million as of September 30, 2017) and exploration and production companies that own interests in properties we operate ($200 million as of September 30, 2017). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parent guarantees for receivables from parties that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we recognized $1 million, $1 million, $7 million and $5 million, respectively, of bad debt expense related to potentially uncollectible receivables.

~~Contractual Obligations and Off-Balance Sheet Arrangements~~

From time to time, we enter into arrangements and transactions that can give rise to contractual obligations and off-balance sheet commitments. As of September 30, 2017, these arrangements and transactions included (i) operating lease agreements, (ii) a volumetric production payment (VPP) (to purchase production and pay related production expenses and taxes in the future), (iii) open purchase commitments, (iv) open delivery commitments, (v) open drilling commitments, (vi) undrawn letters of credit, (vii) open gathering and transportation commitments, and (viii) various other commitments we enter into in the ordinary course of business that could result in a future cash obligation.carbon capture project. See ~~Notes 4 and 9~~Note 12 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further ~~discussion~~discussion.

Table of ~~commitments~~Contents

Payments on New Credit Facility, net

During the first three months of 2023, we made net repayments of $1,050 million on the New Credit Facility, utilizing a portion of the divestiture proceeds from the sale of a portion of our Eagle Ford assets and ~~VPPs,~~also from internally generated cash provided by operating activities.

Cash Paid to Repurchase and Retire Common Stock

In March 2022, we commenced our share repurchase program. During the first three months of 2023, we repurchased 0.8 million shares for an aggregate price of $60 million, which is inclusive of shares for which cash settlement occurred in early April 2023. During the first three months of 2022, we repurchased 1 million shares of common stock for an aggregate price of $83 million. The repurchased shares of common stock were retired and recorded as a reduction to common stock and retained earnings.

Cash Paid for Common Stock Dividends

As part of our dividend program, we paid common stock base dividends of $75 million and common stock variable dividends of $100 million during the first three months of 2023.


Results of Operations

Natural Gas, Oil and NGL Production and Average Sales Prices


	Three Months Ended March 31, 2023
	Natural Gas		Oil		NGL		Total
	MMcf per day	$/Mcf	MBbl per day	$/Bbl	MBbl per day	$/Bbl	MMcfe per day	$/Mcfe
Marcellus	1,974	3.47	—	—	—	—	1,974	3.47
Haynesville	1,549	2.88	—	—	—	—	1,549	2.88
Eagle Ford	128	1.97	54	76.82	16	26.71	546	8.82
Total	3,651	3.17	54	76.82	16	26.71	4,069	3.97

Average NYMEX Price		3.42		76.13
Average Realized Price (including realized derivatives)		2.74		66.79		26.71		3.45

	Three Months Ended March 31, 2022
	Natural Gas		Oil		NGL		Total
	MMcf per day	$/Mcf	MBbl per day	$/Bbl	MBbl per day	$/Bbl	MMcfe per day	$/Mcfe
Marcellus	1,452	4.66	—	—	—	—	1,452	4.66
Haynesville	1,625	4.46	—	—	—	—	1,625	4.46
Eagle Ford	129	4.04	52	95.00	16	41.09	540	11.44
Powder River Basin	41	5.45	8	95.18	3	53.96	102	10.66
Total	3,247	4.54	60	95.02	19	43.05	3,719	5.72

Average NYMEX Price		4.95		94.29
Average Realized Price (including realized derivatives)		3.08		65.64		43.05		3.96

Natural Gas, Oil and NGL Sales


	Three Months Ended March 31, 2023
	Natural Gas		Oil		NGL		Total
Marcellus	$	617	$	—	$	—	$	617
Haynesville	402		—		—		402
Eagle Ford	23		373		38		434

Total natural gas, oil and NGL sales	$	1,042	$	373	$	38	$	1,453

	Three Months Ended March 31, 2022
	Natural Gas		Oil		NGL		Total
Marcellus	$	609	$	—	$	—	$	609
Haynesville	652		—		—		652
Eagle Ford	47		450		57		554
Powder River Basin	20		66		13		99
Total natural gas, oil and NGL sales	$	1,328	$	516	$	70	$	1,914

Natural gas, oil and NGL sales during the first three months of 2023 decreased $461 million compared to the first three months of 2022. Lower average prices, which were consistent with the downward trend in index prices for all products, drove a $512 million decrease during the first three months of 2023. Additionally, the Powder River Basin divestiture and lower sales volumes in Haynesville resulted in decreases of $99 million and $19 million, respectively. Partially offsetting these decreases was an increase of $162 million due to increased sales volumes in

~~Results~~Marcellus, primarily due to the Marcellus Acquisition in March 2022, and an increase of ~~Operations – Three Months Ended September 30, 2017 vs September 30, 2016~~$7 million due to increased Eagle Ford sales volumes.

~~General. For~~Production Expenses


	Three Months Ended March 31, 2023			Three Months Ended March 31, 2022
			$/Mcfe			$/Mcfe
Marcellus	$	24	0.13	$	13	0.10
Haynesville	47		0.34	32		0.22
Eagle Ford	60		1.23	55		1.15
Powder River Basin	—		—	10		0.94
Total production expenses	$	131	0.36	$	110	0.33

Production expenses during the ~~Current Quarter, Chesapeake had a net loss~~first three months of ~~$17~~2023 increased $21 million ~~or $0.05 per diluted common share, on total revenues~~as compared to the first three months of ~~$1.943 billion. This compares to a net loss of $1.214 billion, or $1.62 per diluted common share, on total revenues of $2.276 billion for the Prior Quarter.~~2022. The ~~net loss in the Current Quarter~~increase was primarily due to ~~non-cash unrealized hedging losses. The net loss~~an increase in saltwater disposal expenses, workovers and other preventative maintenance in Eagle Ford and Haynesville, as well as the Marcellus Acquisition in March 2022. These increases were partially offset by the divestiture of the Powder River Basin assets in March 2022.

Gathering, Processing and Transportation Expenses


	Three Months Ended March 31, 2023			Three Months Ended March 31, 2022
			$/Mcfe			$/Mcfe
Marcellus	$	111	0.62	$	71	0.54
Haynesville	68		0.49	65		0.45
Eagle Ford	85		1.73	84		1.73
Powder River Basin	—		—	22		2.32
Total GP&T	$	264	0.72	$	242	0.72

Gathering, processing and transportation expenses during the first three months of 2023 increased $22 million as compared to the first three months of 2022. Marcellus increased $40 million, primarily due to the Marcellus Acquisition in March 2022, while the divestiture of the Powder River Basin assets in March 2022 resulted in a decrease of $22 million.

Severance and Ad Valorem Taxes


	Three Months Ended March 31, 2023			Three Months Ended March 31, 2022
			$/Mcfe			$/Mcfe
Marcellus	$	5	0.03	$	4	0.03
Haynesville	34		0.24	12		0.09
Eagle Ford	30		0.60	36		0.75
Powder River Basin	—		—	11		1.09
Total severance and ad valorem taxes	$	69	0.19	$	63	0.19

Severance and ad valorem taxes during the first three months of 2023 increased $6 million as compared to the first three months of 2022. Legislative action led to changes in the ~~Prior Quarter was primarily driven~~Haynesville severance and ad valorem tax rates, which resulted in an increase of $20 million during the first three months of 2023. These increases were partially offset by ~~non-cash impairments~~an $11 million decrease attributable to the divestiture of ~~fixed assets and other and impairments~~the Powder River Basin assets.

Adjusted Gross Margin by Operating Area

The tables below present the adjusted gross margin for each of our operating areas. Adjusted gross margin is defined as natural gas, oil and ~~natural gas properties. See~~ ~~Impairment~~NGL sales less production expenses, gathering, processing and transportation expenses, and severance and ad valorem taxes. Adjusted gross margin is a non-GAAP measure, and a reconciliation of ~~Oil and Natural Gas Properties and Impairments~~gross margin to adjusted gross margin is presented within the “Non-GAAP Measures” section of ~~Fixed Assets and Other~~ ~~below.~~this Item 2.

~~Oil,~~


	Three Months Ended March 31, 2023			Three Months Ended March 31, 2022
			$/Mcfe			$/Mcfe
Marcellus	$	477	2.69	$	521	3.99
Haynesville	253		1.81	543		3.70
Eagle Ford	259		5.26	379		7.81
Powder River Basin	—		—	56		6.31
Adjusted gross margin	$	989	2.70	$	1,499	4.48

Natural Gas and ~~NGL Sales~~. During the Current Quarter, oil, natural gas and NGL sales were $979 million compared to $1.177 billion in the Prior Quarter. In the Current Quarter, Chesapeake sold 50 mmboe for $1.049 billion at a weighted average price of $21.06 per boe (excluding the effect of derivatives), compared to 59 mmboe sold in the Prior Quarter for $1.048 billion at a weighted average price of $17.86 per boe (excluding the effect of derivatives). The increase in the price received per boe in the Current Quarter compared to the Prior Quarter resulted in a $159 million increase in revenues, and decreased sales volumes resulted in a $158 million decrease in revenues, for a total net increase in revenues of $1 million (excluding the effect of derivatives).Oil Derivatives

For the Current Quarter, our average price received per barrel of oil (excluding the effect of derivatives) was $47.94, compared to $42.94 in the Prior Quarter. Natural gas prices received per mcf (excluding the effect of derivatives) were $2.52 and $2.32 in the Current Quarter and the Prior Quarter, respectively. NGL prices received per barrel (excluding the price of derivatives) were $21.83 in the Current Quarter and $13.93 in the Prior Quarter.


	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022
Natural gas derivatives - realized losses	$	(140)	$	(428)
Natural gas derivatives - unrealized gains (losses)	1,021		(1,372)
Total gains (losses) on natural gas derivatives	$	881	$	(1,800)

Oil derivatives - realized losses	$	(49)	$	(159)
Oil derivatives - unrealized gains (losses)	98		(166)
Total gains (losses) on oil derivatives	49		(325)
Total gains (losses) on natural gas and oil derivatives	$	930	$	(2,125)

Gains (losses) from our oil, natural gas and NGL derivatives resulted in a net decrease in oil, natural gas and NGL revenues of $70 million in the Current Quarter and a net increase of $129 million in the Prior Quarter, respectively. See ~~Item 3.~~ ~~Quantitative and Qualitative Disclosures About Market Risk~~ ~~in Part Iof this report for a listing of all of our derivative instruments as of September 30, 2017.~~

A change in oil, natural gas and NGL prices has a significant impact on our revenues and cash flows. Assuming our Current Quarter production levels and without considering the effect of derivatives, an increase or decrease of $1.00 per barrel of oil sold would result in an increase or decrease in Current Quarter revenues and cash flows of approximately $8 million, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in Current Quarter revenues and cash flows of approximately $22 million, and an increase or decrease of $1.00 per barrel of NGL sold would result in an increase or decrease in Current Quarter revenues and cash flows of approximately $5 million.

~~The following tables show average daily production and average sales prices received by our operating divisions for the Current Quarter and the Prior Quarter:~~

Three Months Ended September 30, 2017
Oil Natural Gas NGL Total

mbbl
per day

$/bbl^(a)

mmcf
per day

$/mcf^(a)

mbbl
per day

$/bbl^(a)

mboe
per day
%
$/boe^(a)
Marcellus —
—
757
1.95
—
—
126
24
11.70
Haynesville —
—
805
2.76
—
—
134
25
16.59
Eagle Ford 52
49.08
136
3.25
18
23.07
93
17
36.91
Utica 12
44.18
475
2.76
28
20.31
120
22
20.21
Mid-Continent 16
47.28
174
2.58
11
22.78
56
10
26.10
Powder River Basin 6
47.12
35
2.91
2
26.77
13
2
31.01
Other^(b)
—
—
—
—
—
—
—
—
—
Total 86
47.94
2,382
2.52
59
21.83
542
100 % 21.06

Three Months Ended September 30, 2016
Oil Natural Gas NGL Total
mbbl
per day
$/bbl^(a)
mmcf
per day
$/mcf^(a)
mbbl
per day
$/bbl^(a)
mboe
per day %
$/boe^(a)
Marcellus —
—
806
1.62
—
—
134
22
9.72
Haynesville —
—
835
2.59
—
—
139
22
15.55
Eagle Ford 59
43.80
145
3.00
18
14.97
101
15
32.35
Utica 11
37.77
498
2.60
33
12.79
127
20
16.80
Mid-Continent 12
43.87
203
2.48
9
16.37
55
9
21.53
Powder River Basin 5
42.16
37
2.64
3
15.80
14
2
25.68
Other^(b)
—
—
390
2.46
3
10.68
68
10
14.63
Total 87
42.94
2,914
2.32
66
13.93
638
100 % 17.86


~~(a)~~	~~Average sales prices exclude gains and/or losses on derivatives.~~


~~(b)~~	~~Includes Central Texas and the Devonian Shale which were divested in the 2016 fourth quarter.~~

Our average daily production of 542 mboe for the Current Quarter consisted of approximately 86 mbbls of oil (16% on an oil equivalent basis), approximately 2,382 mmcf of natural gas (73% on an oil equivalent basis) and approximately 59 mbbls of NGL (11% on an oil equivalent basis). Oil production decreased by 1%, natural gas production decreased by 18% and NGL production decreased by 11% year over year primarily as a result of the sale of certain of our Barnett, Mid-Continent and Devonian assets in 2016 and the sale of certain of our Haynesville Shale assets in 2017.

Table of ~~contract assignments~~Contents

~~Excluding the impact of derivatives, our percentage of revenues from oil, natural gas and NGL is shown in the following table:~~

Three Months Ended
September 30,
2017 2016
Oil 36
33
Natural gas 53
59
NGL 11
8
Total 100 % 100 %

~~Marketing, Gathering and Compression Revenues and Expenses. Marketing, gathering and compression revenues consist of third-party revenues, and historically, the fair value adjustments on our supply contract derivatives (see~~ Note 811 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for ~~additional information on~~a discussion of our ~~supply contract derivatives).~~derivative activity.

General and Administrative Expenses ~~related to our marketing, gathering and compression operations consist of third-party expenses and exclude depreciation and amortization,~~


	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022

Total G&A, net	$	35	$	26
G&A, net per Mcfe	$	0.09	$	0.08

Total general and administrative expenses, ~~impairments~~net during the first three months of ~~fixed assets and other, net gains or losses on sales of fixed assets and interest expense. See~~ ~~Depreciation and Amortization of Other Assets~~ ~~below for the depreciation and amortization recorded on our marketing, gathering and compression assets. We recognized $964~~2023 increased $9 million in marketing, gathering and compression revenues in the Current Quarter with corresponding expenses of $978 million, for a net loss of $14 million. This compares to revenues of $1.099 billion, of which $146 million related to cash proceeds from the sale of our long-term natural gas supply contract to a third party offset by the reversal of the cumulative unrealized gains of $280 million, with corresponding expenses of $1.261 billion, for a net loss of $162 million in the Prior Quarter. Although higher oil, natural gas and NGL prices were paid and received in our marketing operations, revenues and expenses decreased in the Current Quarter compared to the ~~Prior Quarter~~first three months of 2022, primarily due to adjustments in employee benefits and compensation as ~~a result~~well as increases in other corporate expenses.

Depreciation, Depletion and ~~terminations.~~Amortization

~~Oil, Natural Gas and NGL Production Expenses~~. Production expenses, which include lifting costs and ad valorem taxes, were $151 million in the Current Quarter, compared to $164 million in the Prior Quarter. The decrease in the Current Quarter was primarily a result of the sale of certain oil and natural gas properties in 2016 and 2017. On a unit-of-production basis, production expenses were $3.03 per boe in the Current Quarter compared to $2.80 per boe in the Prior Quarter. The per unit increase in the Current Quarter was the result of higher workover and repair and maintenance expenses. Production expenses in the Current Quarter and the Prior Quarter included approximately $5 million and $10 million, or $0.10 and $0.17 per boe, respectively, associated with VPP production volumes. In connection with certain 2016 divestitures, we purchased the remaining oil and natural gas interests previously sold in connection with five of our VPPs, and a majority of these repurchased oil and natural gas interests were subsequently sold. We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve.


	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022
DD&A	$	390	$	409
DD&A per Mcfe	$	1.06	$	1.22

~~Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses.~~ Oil, natural gas and NGL gathering, processing and transportation expenses were $369 million in the Current Quarter compared to $473 million in the Prior Quarter. On a unit-of-production basis, gathering, processing and transportation expenses were $7.40 per boe in the Current Quarter compared to $8.07 per boe in the Prior Quarter. The absolute and per unit ~~decrease~~decreases in depreciation, depletion and amortization for the first three months of 2023 compared to the first three months of 2022, are primarily related to our Eagle Ford divestitures, partially offset by an increase related to the Marcellus Acquisition in ~~2016~~March 2022. We cease recording depreciation on assets that are classified as held for sale.

Other Operating Expense, Net


	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022
Other operating expense, net	$	3	$	23

During the first three months of 2022, we recognized approximately $23 million of costs related to our Marcellus Acquisition, which included consulting fees, financial advisory fees, legal fees and ~~2017. A summary~~change in control expense in accordance with Chief’s existing employment agreements.

Interest Expense


	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022

Interest expense on debt	$	46	$	38

Amortization of premium, issuance costs and other	(2)		(1)
Capitalized interest	(7)		(5)
Total interest expense	$	37	$	32

The increase in total interest expense during the first three months of ~~oil, natural gas and NGL gathering, processing and transportation expenses by product is shown below.~~

Three Months Ended
September 30,
2017 2016
Oil ($ per bbl) $ 4.33
$ 3.67
Natural gas ($ per mcf) $ 1.34
$ 1.47
NGL ($ per bbl) $ 7.40
$ 8.13

~~Production Taxes. Production taxes were $21 million in the Current Quarter~~2023 compared to ~~$17 million in~~ the Prior Quarter. On a unit-of-production basis, production taxes were $0.43 per boe in the Current Quarter compared to $0.29 per boe in the Prior Quarter. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil, natural gas and NGL prices are higher. The absolute and per unit increase in production taxes in the Current Quarterfirst three months of 2022 was primarily due to higher ~~prices received~~average debt outstanding between periods.

Income Taxes

Income tax expense was $404 million for ~~our oil, natural gas and NGL production. Production taxes in both~~ the ~~Current Quarter and the Prior Quarter included $1~~first three months of 2023. Of this amount, $26 million ~~or $0.01 and $0.02 per boe, respectively, associated with VPP production volumes.~~

~~General and Administrative Expenses~~. General and administrative expenses were $54 million in the Current Quarter and $63 million in the Prior Quarter, or $1.08 per boe in both the Current Quarter and the Prior Quarter. Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, drilling and completion activities are capitalized. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, and we do not include any costs related to production, general corporate overhead or similar activities. We capitalized $37 million and $38 million of internal costs in the Current Quarter and the Prior Quarter, respectively, directly related to our leasehold acquisition and drilling and completion efforts.

~~Provision for Legal Contingencies.~~ In the Current Quarter and the Prior Quarter, we recorded expense of $20 million and $8 million, respectively, for legal contingencies. Both the Current Quarter and the Prior Quarter provisions consist of adjustments for loss contingencies primarily related to royalty claims. See Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of royalty claims.

~~Oil, Natural Gas and NGL Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (DD&A) of oil, natural gas and NGL properties~~ was ~~$228 million and $251 million in the Current Quarter and the Prior Quarter, respectively. The decrease in the Current Quarter was primarily~~ the result of ~~decreased production~~projecting current federal and state income taxes, predominately as a result of ~~the sale of certain of our Barnett and Mid-Continent assets in 2016~~taxable gains on closed divestitures, and the ~~sale of certain of our Haynesville Shale assets in 2017. The average DD&A rate per boe, which~~remainder is ~~a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $4.57 and $4.26 in the Current Quarter and the Prior Quarter, respectively.~~

~~Depreciation and Amortization of Other Assets~~. Depreciation and amortization of other assets was $20 million in the Current Quarter compared to $25 million in the Prior Quarter. On a unit-of-production basis, depreciation and amortization of other assets was $0.41 per boe in the Current Quarter compared to $0.42 per boe in the Prior Quarter. Property and equipment costs are depreciated on a straight-line basis over the estimated useful lives of the assets. The following table shows depreciation expense by asset class for the Current Quarter and the Prior Quarter and the estimated useful lives of these assets.

Three Months Ended
September 30,
Estimated
Useful
Life
2017 2016
($ in millions) (in years)
Buildings and improvements $ 9
$ 9
10 – 39
Computers and office equipment 5
5
5 – 7
Natural gas compressors^(a)
4
6
3 – 20
Vehicles —
1
5
Natural gas gathering systems and treating plants^(a)
—
2
20
Other 2
2
5 – 12
Total depreciation and amortization of other assets $ 20
$ 25


~~(a)~~	~~Included in our marketing, gathering and compression operating segment.~~

~~Impairment of Oil and Natural Gas Properties.~~ Our oil and natural gas properties are subject to quarterly full cost ceiling tests. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed a ceiling amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In the Current Quarter, capitalized costs of oil and natural gas properties did not exceed the ceiling. For the Prior Quarter, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment of the carrying value of our oil and natural gas properties of $497 million.

~~Impairments of Fixed Assets and Other.~~ In the Current Quarter and the Prior Quarter, we recognized $9 million and $751 million, respectively, of fixed asset impairment losses and other charges. On October 31, 2016, we conveyed our interests in the Barnett Shale operating area located in north central Texas and simultaneously terminated most of our future commitments associated with this asset. In connection with this transaction, we accrued $334 million of charges in the Prior Quarter related to ~~termination~~projections of ~~a natural gas gathering agreement associated with the Barnett Shale Assets. Additionally, certain of our other property~~deferred federal and equipment, including buildings, surface land, compressors and office equipment, qualified as held for sale as of September 30, 2016. We recognized an impairment charge of $282 million in the Prior Quarter related to these assets representing the difference between the carrying amount and the fair value of the assets, less the anticipated costs to sell. Also in the Prior Quarter, we entered into a purchase and sale agreement to sell the majority of our upstream and midstream assets in the Devonian shale located in West Virginia and Kentucky. We recognized an impairment charge of $134 million in the Prior Quarter for these assets for the difference between the carrying amount and the fair value of the assets, less the anticipated costs to sell.

~~Net Gains on Sales of Fixed Assets.~~ ~~Net gains on sales of fixed assets were $1 million in the Current Quarter. The Current Quarter amounts primarily related to the sale of other property and equipment.~~

~~Interest Expense. Interest expense was $114 million in the Current Quarter compared to $73 million in the Prior Quarter as follows:~~

Three Months Ended
September 30,
2017 2016
($ in millions)
Interest expense on senior notes $ 135
$ 141
Interest expense on term loan 34
14
Amortization of loan discount, issuance costs and other 13
9
Amortization of premium associated with troubled debt restructuring (29 ) (41 )
Interest expense on revolving credit facility 11
10
Realized gains on interest rate derivatives^(a)
(1 ) (3 )
Unrealized losses on interest rate derivatives^(b)
—
2
Capitalized interest (49 ) (59 )
Total interest expense $ 114
$ 73

Average senior notes borrowings $ 7,632
$ 8,348
Average credit facilities borrowings $ 631
$ 245
Average term loan borrowings $ 1,500
$ 636


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


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

The increase in interest expense is primarily due to an increase in term loan interest expense and a decrease in capitalized interest as a result of lower average balances of unproved oil and natural gas properties, the primary asset on which interest is capitalized. Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $2.26 per boe in the Current Quarter compared to $1.20 per boe in the Prior Quarter.

~~Losses on Investments.~~ ~~Losses on investments of $1 million in the Prior Quarter were related to our equity investment in Sundrop Fuels, Inc.~~

~~Gains (Losses) on Purchases or Exchanges of Debt~~. In the Current Quarter, we repurchased $5 million principal amount of our outstanding senior notes and contingent convertible senior notes for $6 million. We recorded an aggregate loss of approximately $1 million associated with the transaction.

In the Prior Quarter, we used the proceeds from our $1.5 billion term loan facility to purchase and retire $898 million principal amount of our senior notes and $708 million principal amount of our contingent convertible senior notes for an aggregate $1.5 billion pursuant to tender offers. We recognized an aggregate gain of $87 million associated with these transactions.

~~Income Tax Expense (Benefit).~~ ~~Chesapeake recorded a nominal amount of~~state income taxes. An income tax benefit inof $46 million was recorded during the ~~Current Quarter.~~first three months of 2022. A tax benefit was recorded during the first three months of 2022 due to the application of our estimated annual effective tax rate to the book net loss before income taxes recorded during the first three months of 2022. Our effective income tax ~~rates were 0.0%~~was 22.5% and 5.7% during the first three months of 2023 and 2022, respectively. The fluctuation in ~~both~~ the Current Quarter and the Prior Quarter. The resulting effective income tax rates for the Current Quarter and the Prior Quarter are primarily due to the offsetting impact of the change in the valuation allowance. Further, our effective tax rate is mainly because we are no longer maintaining a full valuation allowance against our deferred tax assets during the first three months of 2023 as we were during the first three months of 2022. Our effective tax rate can also fluctuate as a result of the impact of discrete items, state income taxes and permanent differences. See Note 12 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of income ~~tax expense (benefit).~~taxes.

~~Net Income Attributable~~


Non-GAAP Measures

Management uses adjusted gross margin to ~~Noncontrolling Interests. Chesapeake recorded net income attributable to noncontrolling interests of $1 million in the Current Quarter~~assess our operating results and ~~the Prior Quarter. In both quarters, activity was attributable to the Chesapeake Granite Wash Trust.~~

~~Results of Operations – Nine Months Ended September 30, 2017 vs September 30, 2016~~

~~General~~. For the Current Period, Chesapeake had net income of $619 million, or $0.56 per diluted common share, on total revenues of $6.977 billion. This compares to a net loss of $4.058 billion, or $5.80 per diluted common share, on total revenues of $5.851 billion for the Prior Period. The increase in net income in the Current Period is attributable to an increase in the average realized prices we received for oil,financial performance across assets and periods. We define adjusted gross margin as natural gas, ~~and NGL production, partially offset by charges for terminating certain natural gas and~~ oil ~~transportation commitments. The net loss in the Prior Period was primarily driven by non-cash impairments of oil and natural gas properties and impairments of fixed assets and other. See~~ ~~Impairment of Oil and Natural Gas Properties~~ ~~and~~ ~~Impairments of Fixed Assets and Other~~ ~~below.~~

~~Oil, Natural Gas and NGL Sales. During the Current Period, oil, natural gas~~ and NGL sales were $3.727 billion compared to $2.610 billion in the Prior Period. In the Current Period, Chesapeake sold 145 mmboe for $3.275 billion at a weighted average price of $22.53 per boe (excluding the effect of derivatives), compared to 180 mmboe sold in the Prior Period for $2.744 billion at a weighted average price of $15.27 per boe (excluding the effect of derivatives). The increase in the price received per boe in the Current Period compared to the Prior Period resulted in a $1.055 billion increase in revenues, and decreased sales volumes resulted in a $524 million decrease in revenues, for a total net increase in revenues of $531 million (excluding the effect of derivatives).

For the Current Period, our average price received per barrel of oil (excluding the effect of derivatives) was $48.53, compared to $38.21 in the Prior Period. Natural gas prices received per mcf (excluding the effect of derivatives) were $2.83 and $1.90 in the Current Period and the Prior Period, respectively. NGL prices received per barrel (excluding the effect of derivatives) were $21.28 and $12.90 in the Current Period and the Prior Period, respectively.

Gains from our oil, natural gas and NGL derivatives resulted in a net increase in oil, natural gas and NGL revenues of $452 million in the Current Period and a net decrease of $134 million in the Prior Period, respectively. See Item 3. ~~Quantitative and Qualitative Disclosures About Market Risk~~ ~~in Part Iof this report for a listing of all of our derivative instruments as of September 30, 2017.~~

~~A change in oil, natural gas and NGL prices has a significant impact on our revenues and cash flows. Assuming our Current Period~~less production levels and without considering the effect of derivatives, an increase or decrease of $1.00 per barrel of oil sold would result in an increase or decrease in Current Period revenues and cash flows of approximately $23 million, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in Current Period revenues and cash flows of approximately $64 million and $63 million, respectively, and an increase or decrease of $1.00 per barrel of NGL sold would result in an increase or decrease in Current Period revenues and cash flows of approximately $15 million.

~~The following tables show average daily production and average sales prices received by our operating divisions for the Current Period and the Prior Period:~~

Nine Months Ended September 30, 2017
Oil Natural Gas NGL Total

mbbl
per day

$/bbl^(a)

mmcf
per day\

$/mcf^(a)

mbbl
per day

$/bbl^(a)

mboe
per day
%
$/boe^(a)
Marcellus —
—
815
2.51
—
—
136
25
15.05
Haynesville —
—
751
2.90
—
—
125
24
17.44
Eagle Ford 55
49.42
139
3.36
18
21.27
96
18
37.22
Utica 9
44.01
411
3.12
26
20.87
104
19
21.52
Mid-Continent 16
48.20
189
2.84
10
21.59
57
11
26.31
Powder River Basin 6
48.12
34
3.06
2
24.52
14
3
31.58
Other^(b)
—
—
—
—
—
—
—
—
—
Total 86
48.53
2,339
2.83
56
21.28
532
100 % 22.53

Nine Months Ended September 30, 2016
Oil Natural Gas NGL Total

mbbl
per day

$/bbl^(a)

mmcf
per day

$/mcf^(a)

mbbl
per day

$/bbl^(a)

mboe
per day
%
$/boe^(a)
Marcellus —
—
825
1.42
—
—
138
21
8.54
Haynesville —
—
754
2.13
—
—
126
19
12.79
Eagle Ford 55
39.72
138
2.40
17
13.28
95
14
28.78
Utica 14
32.44
514
2.15
34
12.26
134
21
14.75
Mid-Continent 16
38.15
279
1.87
13
13.95
76
12
17.44
Powder River Basin 6
38.22
39
2.20
3
15.60
15
2
23.74
Other^(b)
—
—
421
1.94
3
10.82
72
11
11.64
Total 91
38.21
2,970
1.90
70
12.90
656
100 % 15.27


~~(a)~~	~~Average sales prices exclude gains and/or losses on derivatives.~~


~~(b)~~	~~Includes Central Texas and the Devonian Shale which were divested in the 2016 fourth quarter.~~

Our average daily production of 532 mboe for the Current Period consisted of approximately 86 mbbls of oil (16% on an oil equivalent basis), approximately 2,339 mmcf of natural gas (73% on an oil equivalent basis) and approximately 56 mbbls of NGL (11% on an oil equivalent basis). Oil production decreased by 6%, natural gas production decreased by 22% and NGL production decreased by 19% year over year primarily as a result of the sale of certain of our Barnett, Mid-Continent and Devonian assets in 2016 and the sale of certain of our Haynesville Shale assets in 2017.

~~Excluding the impact of derivatives, our percentage of revenues from oil, natural gas and NGL is shown in the following table:~~

Nine Months Ended
September 30,
2017 2016
Oil 35
35
Natural gas 55
56
NGL 10
9
Total 100 % 100 %

~~Marketing, Gathering and Compression Revenues and Expenses~~. Marketing, gathering and compression revenues consist of third-party revenues, and historically, the fair value adjustments on our supply contract derivatives (see Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for additional information on our supply contract derivatives). Expenses related to our marketing, gathering and compression operations consist of third-party expenses, ~~and exclude depreciation and amortization, general and administrative expenses, impairments of fixed assets and other, net gains or losses on sales of fixed assets and interest expense. See~~ ~~Depreciation and Amortization of Other Assets~~ below for the depreciation and amortization recorded on our marketing, gathering and compression assets. We recognized $3.250 billion in marketing, gathering and compression revenues in the Current Period with corresponding expenses of $3.333 billion, for a net loss of $83 million. This compares to revenues of $3.241 billion, of which $146 million related to cash proceeds from the sale of our long-term natural gas supply contract to a third party offset by the reversal of the cumulative unrealized gains of $297 million, with corresponding expenses of $3.410 billion, for a net loss of $169 million in the Prior Period. Revenues increased in the Current Period compared to the Prior Period primarily as a result of higher oil, natural gas and NGL prices paid and received in our marketing operations. The margin increase in the Current Period as compared to the Prior Period was primarily the result of the sale of a significant portion of our gathering and compression assets, concurrently with the associated upstream assets. Additionally, the Current Period includes losses on certain transportation contracts with third parties associated with assets divested in the fourth quarter of 2016.

~~Oil, Natural Gas and NGL Production Expenses~~. Production expenses, which include lifting costs and ad valorem taxes, were $426 million in the Current Period, compared to $552 million in the Prior Period. On a unit-of-production basis, production expenses were $2.93 per boe in the Current Period compared to $3.07 per boe in the Prior Period. The absolute and per unit decrease in the Current Period was the result of operating efficiencies across most of our operating areas, as well as the sale of certain oil and natural gas properties in 2016. Production expenses in the Current Period and the Prior Period included approximately $15 million and $38 million, or $0.11 and $0.21 per boe, respectively, associated with VPP production volumes. In connection with certain 2016 divestitures, we purchased the remaining oil and natural gas interests previously sold in connection with five of our VPPs, and a majority of these repurchased oil and natural gas interests were subsequently sold. We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve.

~~Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses.~~ ~~Oil, natural gas and NGL~~ gathering, processing and transportation expenses, ~~were $1.081 billion~~and severance and ad valorem taxes.

Adjusted gross margin is not a measure of financial performance under GAAP and should not be considered in ~~the Current Period compared to~~ ~~$1.436 billion~~ ~~in the Prior Period. On~~isolation or as a unit-of-production basis, gathering, processing and transportation expenses were $7.43 per boe in the Current Period compared to $7.99 per boe in the Prior Period. The absolute and per unit decrease primarily related to divestitures in 2016. A summary of oil, natural gas and NGL gathering, processing and transportation expenses by product is shown below.

Nine Months Ended
September 30,
2017 2016
Oil ($ per bbl) $ 3.96
$ 3.53
Natural gas ($ per mcf) $ 1.36
$ 1.47
NGL ($ per bbl) $ 7.90
$ 7.77

~~Production Taxes~~. Production taxes were $64 million in the Current Period compared to $54 million in the Prior Period. On a unit-of-production basis, production taxes were $0.44 per boe in the Current Period compared to $0.30 per boe in the Prior Period. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil, natural gas and NGL prices are higher. The absolute and per unit increase in production taxes in the Current Period was primarily due to higher prices receivedsubstitute for our oil, natural gas and NGL production. Production taxes in the Current Period and the Prior Period included $1 million and $3 million, or a nominal amount and $0.02 per boe, respectively, associated with VPP production volumes.

~~General and Administrative Expenses~~. General and administrative expenses were $189 million in the Current Period and $172 million in the Prior Period, or $1.30 and $0.96 per boe, respectively. The absolute and per unit expense increase in the Current Period was primarily due to less overhead reflected as oil, natural gas and NGL production expenses, as well as less overhead billed to third party working interest owners, resulting from certain divestitures in 2016 and 2017.

Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, drilling and completion activities are capitalized. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, and we do not include any costs related to production, general corporate overhead or similar activities. We capitalized $105 million and $110 million of internal costs in the Current Period and the Prior Period, respectively, directly related to our leasehold acquisition and drilling and completion efforts.

~~Restructuring and Other Termination Costs.~~ ~~We recorded an expense of $3 million in the Prior Period for restructuring and other termination costs primarily related to the reduction in workforce in connection with the restructuring~~analysis of our ~~compressor manufacturing subsidiary.~~

~~Provision for Legal Contingencies.~~ In the Current Period and the Prior Period, we recorded expense of $35 million and $112 million, respectively, for legal contingencies. Both the Current Period and the Prior Period provisions consist of adjustments for loss contingencies primarily relatedresults reported under GAAP. Additionally, adjusted gross margin may not be comparable to ~~royalty claims. See Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of royalty claims.~~

~~Oil, Natural Gas and NGL Depreciation, Depletion and Amortization. Depreciation,~~similarly titled measures used by other companies. We exclude depreciation, depletion and amortization ~~(DD&A)~~from the calculation of oil, natural gas and NGL properties was $627 million and $791 million in the Current Period and the Prior Period, respectively. The average DD&A rate per boe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $4.31 and $4.40 in the Current Period and the Prior Period, respectively. The absolute and per unit decrease in the Current Period was primarily the result of the sale of certain of our Barnett and Mid-Continent assets in 2016 and the sale of certain of our Haynesville Shale assets in 2017.

~~Depreciation and Amortization of Other Assets. Depreciation~~adjusted gross margin as depreciation, depletion and amortization ~~of other assets was $62 million in the Current Period compared~~are non-cash expenses that do not necessarily reflect present-day performance. The table below reconciles gross margin, as defined by GAAP, to $83 million in the Prior Period. On a unit-of-production basis, depreciation and amortization of other assets was $0.43 per boe in the Current Period compared to $0.46 per boe in the Prior Period. Property and equipment costs are depreciated on a straight-line basis over the estimated useful lives of the assets. The following table shows depreciation expense by asset class for the Current Period and the Prior Period and the estimated useful lives of these assets.adjusted gross margin.


	Three Months Ended March 31, 2023		Three Months Ended March 31, 2022

Gross margin (GAAP)
Natural gas, oil and NGL sales	$	1,453	$	1,914
Less:
Production expenses	(131)		(110)
Gathering, processing and transportation expenses	(264)		(242)
Severance and ad valorem taxes	(69)		(63)
Depreciation, depletion and amortization	(390)		(409)
Gross margin (GAAP)	599		1,090
Add back: Depreciation, depletion and amortization	390		409
Adjusted gross margin (Non-GAAP)	$	989	$	1,499

Nine Months Ended
September 30,
Estimated
Useful
Life
2017 2016
($ in millions) (in years)
Buildings and improvements $ 27
$ 29
10 – 39
Computers and office equipment 16
15
5 – 7
Natural gas compressors^(a)
12
20
3 – 20
Vehicles 1
2
5
Natural gas gathering systems and treating plants^(a)
—
7
20
Other 6
10
5 – 12
Total depreciation and amortization of other assets $ 62
$ 83


~~(a)~~			~~Included in our marketing, gathering and compression operating segment.~~Forward-Looking Statements

~~Impairment of Oil and Natural Gas Properties.~~ Our oil and natural gas properties are subject to quarterly full cost ceiling tests. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed a ceiling amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In the Current Period, capitalized costs of oil and natural gas properties did not exceed the ceiling. For the Prior Period, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment of the carrying value of our oil and natural gas properties of $2.564 billion.

~~Impairments of Fixed Assets and Other.~~ In the Current Period and the Prior Period, we recognized $426 million and $795 million, respectively, of fixed asset impairment losses and other charges. In the Current Period, we paid $290 million to assign an oil transportation agreement to a third party. In addition, we terminated future natural gas transportation commitments related to divested assets for a cash payment of $126 million. On October 31, 2016, we

conveyed our interests in the Barnett Shale operating area located in north central Texas and simultaneously terminated most of our future commitments associated with this asset. In connection with this transaction, we accrued $334 million of charges in the Prior Period related to termination of a natural gas gathering agreement associated with the Barnett Shale Assets. Additionally, certain of our other property and equipment, including buildings, surface land, compressors and office equipment, qualified as held for sale as of September 30, 2016. We recognized an impairment charge of $282 million in the Prior Period related to these assets representing the difference between the carrying amount and the fair value of the assets, less the anticipated costs to sell. Also in the Prior Period, we entered into a purchase and sale agreement to sale the majority of our upstream and midstream assets in the Devonian shale located in West Virginia and Kentucky. We recognized an impairment charge of $134 million in the Prior Period for these assets for the difference between the carrying amount and the fair value of the assets, less the anticipated costs to sell.

~~Net Gains on Sales of Fixed Assets.~~ ~~In the Prior Period, net gains on sales of fixed assets were $5 million. The Prior Period amounts primarily related to the sale of buildings, land and other property and equipment.~~

~~Interest Expense. Interest expense was $302 million in the Current Period compared to $197 million in the Prior Period as follows:~~

Nine Months Ended
September 30,
2017 2016
($ in millions)
Interest expense on senior notes $ 407
$ 446
Interest expense on term loan 98
14
Amortization of loan discount, issuance costs and other 28
27
Amortization of premium associated with troubled debt restructuring (112 ) (124 )
Interest expense on revolving credit facility 28
27
Realized gains on interest rate derivatives^(a)
(3 ) (9 )
Unrealized losses on interest rate derivatives^(b)
3
7
Capitalized interest (147 ) (191 )
Total interest expense $ 302
$ 197

Average senior notes borrowings $ 7,640
$ 8,945
Average credit facilities borrowings $ 330
$ 257
Average term loan borrowings $ 1,500
$ 213


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


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

The increase in interest expense is primarily due to an increase in term loan interest expense and a decrease in capitalized interest as a result of lower average balances of unproved oil and natural gas properties, the primary asset on which interest is capitalized. The overall increase in interest expense is offset in part by a decrease in interest expense on senior notes due to the decrease in the average outstanding principal amount of senior notes. Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $2.05 per boe in the Current Period compared to $1.06 per boe in the Prior Period.

~~Losses on Investments.~~ ~~Losses on investments of $3 million in the Prior Period were related to our equity investment in Sundrop Fuels, Inc.~~

~~Loss on Sale of Investment~~. In the Prior Period, we sold certain of our mineral interests and assigned our partnership interest in Mineral Acquisition Company I, L.P. to KKR Royalty Aggregator LLC. As a result of the transaction, we wrote off our equity investment and recognized a $10 million loss.

~~Gains (Losses) on Purchases or Exchanges of Debt~~. In the Current Period, we retired $1.609 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $1.751 billion, which included the maturity of our 6.25% Euro-denominated Senior Notes due 2017 and the corresponding cross currency swap. We recorded an aggregate gain of approximately $183 million associated with the repurchases and tender offers.

~~Income Tax Expense (Benefit).~~ Chesapeake recorded an income tax expense of $2 million in the Current Period. Our effective income tax rate was 0.3% in the Current Period and 0.0% in the Prior Period. The increase in the effective income tax rate from the Prior Period to the Current Period is primarily due to the accrual of current state income tax expenses in the Current Period. Further, our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences. See Note 12 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of income tax expense (benefit).

~~Net Income Attributable to Noncontrolling Interests~~. Chesapeake recorded net income attributable to noncontrolling interests of $3 million and $1 million in the Current Period and the Prior Period, respectively. In both periods, activity was attributable to the Chesapeake Granite Wash Trust.

~~Forward-Looking Statements~~

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Forward-looking statements ~~give~~include our current expectations or forecasts of future ~~events. They include expected oil, natural gas~~events, including matters relating to the continuing effects of the impact of inflation and ~~NGL production~~commodity price volatility resulting from Russia’s invasion of Ukraine, COVID-19 and ~~future expenses, estimated operating costs, assumptions regarding future oil, natural gas~~related supply chain constraints, and ~~NGL prices, planned drilling activity, estimates~~the impact of ~~future drilling~~each on our business, financial condition, results of operations and ~~completion~~cash flows, the potential effects of the Plan on our operations, management, and employees, actions by, or disputes among or between, members of OPEC+ and other ~~capital expenditures (including the use of joint venture drilling carries), potential future write-downs of~~foreign oil-exporting countries, market factors, market prices, our ~~oil and natural gas assets, anticipated sales, and the adequacy of our provisions for legal contingencies, as well as statements concerning anticipated cash flow and liquidity,~~ ability to ~~fund planned capital expenditures and~~meet debt service requirements, our ability to continue to pay cash dividends, the amount and ~~comply with financial maintenance covenants, meet contractual~~timing of any cash ~~commitments to third parties, debt repurchases, operating~~dividends, and ~~capital efficiencies, business strategy, the effect of~~ our ~~remediation plan for a material weakness,~~ESG initiatives. Forward-looking and other statements in this Form 10-Q regarding our environmental, social and other sustainability plans and ~~objectives~~goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking environmental, social and sustainability-related statements may be based on standards for ~~future operations. Disclosures concerning the fair values of derivative contracts~~measuring progress that are still developing, internal controls and ~~their estimated contribution~~processes that continue to ~~our future results of operations are based upon market information as of a specific date. These market prices~~evolve, and assumptions that are subject to ~~significant volatility.~~change in the future. Forward-looking statements often address our expected future business, financial performance and financial condition, and often contain words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy.”

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

•the impact of inflation and commodity price volatility resulting from ~~expected results are described~~Russia’s invasion of Ukraine, COVID-19 and related labor and supply chain constraints, along with the effects of the current global economic environment, including impacts from higher interest rates and recent bank closures and liquidity concerns at certain financial institutions, on our business, financial condition, employees, contractors, vendors and the global demand for natural gas and oil and U.S. and on world financial markets;

•our ability to comply with the covenants under ~~Risk Factors~~ ~~in Item 1A~~ ofthe credit agreement for our ~~annual report on Form 10-K for the year ended December 31, 2016 (2016 Form 10-K)~~New Credit Facility and ~~include:~~other indebtedness;

•risks related to acquisitions or dispositions, or potential acquisitions or dispositions;

•our ability to realize anticipated cash cost reductions;

•the volatility of ~~oil,~~ natural gas, oil and NGL ~~prices;~~prices, which are affected by general economic and business conditions, as well as increased demand for (and availability of) alternative fuels and electric vehicles;

~~the limitations our level of indebtedness may have on our financial flexibility;~~•a deterioration in general economic, business or industry conditions;

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

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

~~our credit rating requiring us to post more collateral under certain commercial arrangements;~~

~~write-downs of our oil and natural gas asset carrying values due to low commodity prices;~~

~~our ability to replace reserves and sustain production;~~

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

•our ability to replace reserves and sustain production;

•drilling and operating risks and resulting liabilities;

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

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

•our ability to achieve and maintain ESG certifications, goals and commitments;

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

•the availability of cash flows from operations and other funds to fund cash dividends and repurchases of equity securities, to finance reserve replacement costs and/or satisfy our debt obligations;

•write-downs of our natural gas and oil asset carrying values due to low commodity prices;

•charges incurred in response to market conditions;

•limited control over properties we do not operate;

•leasehold terms expiring before production can be established;

•commodity derivative activities resulting in lower prices realized on ~~oil,~~ natural gas, oil and NGL sales;

•the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations;

•potential OTC derivatives regulations limiting our ability to hedge against commodity price fluctuations;

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

~~charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity;~~

~~drilling and operating risks and resulting liabilities;~~

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

~~legislative and regulatory initiatives further regulating hydraulic fracturing;~~

•our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used;

~~impacts of potential legislative and regulatory actions addressing climate change;~~

~~federal and state tax proposals affecting our industry;~~

~~potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations;~~

~~competition in the oil and gas exploration and production industry;~~

~~a deterioration in general economic, business or industry conditions;~~

~~negative public perceptions of our industry;~~

~~limited control over properties we do not operate;~~

•pipeline and gathering system capacity constraints and transportation interruptions;

•legislative, regulatory and ESG initiatives, addressing environmental concerns, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal;

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

~~potential challenges by SSE’s former creditors of our spin-off of in connection with SSE’s recently completed bankruptcy under Chapter 11 of the U.S. Bankruptcy Code;~~

•an interruption in operations at our headquarters due to a catastrophic event;

•federal and state tax proposals affecting our industry;

•competition in the ~~continuation~~natural gas and oil exploration and production industry;

•negative public perceptions of ~~suspended dividend payments~~our industry;

•effects of purchase price adjustments and indemnity obligations;

•the ability to execute on our ~~common stock;~~business strategy following emergence from bankruptcy; and

~~the effectiveness~~•other factors that are described under Risk Factors in Item 1A of our ~~remediation plan for a material weakness;~~

~~certain anti-takeover provisions that affect shareholder rights; and~~

~~our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means.~~202 2 Form 10-K.

We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation to update this ~~information except as required by applicable law.~~information. We urge you to carefully review and consider the disclosures in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.


Information About Us

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

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


ITEM 3.			Quantitative and Qualitative Disclosures About Market Risk

~~Oil, Natural Gas~~The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to our risk of loss arising from adverse changes in natural gas, oil and NGL ~~Derivatives~~prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Commodity Price Risk

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

Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse oil, natural gas and NGL price changes is to hedge into strengthening oil and natural gas futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends.

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

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

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

~~We have determined~~ the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to ~~Chesapeake~~us are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 81 1 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the fair value measurements associated with our derivatives.

Our natural gas, oil and NGL revenues during the first three months of 2023, excluding any effect of our derivative instruments, were $1,042 million, $373 million and $38 million, respectively. Based on production, natural gas, oil and NGL revenue for the first three months of 2023 would have increased or decreased by approximately $104 million, $37 million, and $4 million, respectively, for each 10% increase or decrease in prices. As of ~~September 30, 2017~~,March 31, 2023, the fair values of our ~~oil,~~ natural gas and ~~NGL derivative instruments consisted~~oil derivatives were net assets of ~~the following types of instruments:~~

~~Swaps: Chesapeake receives a fixed price~~$508 million and ~~pays a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options and call swaptions.~~

~~Options: Chesapeake sells, and occasionally buys, call options~~$11 million, respectively. A 10% increase in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options, and Chesapeake receives the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

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

~~As of~~ ~~September 30, 2017, we had the following open oil,~~forward natural gas ~~and NGL derivative instruments:~~

Weighted Average Price Fair Value
Volume Fixed Call Put Differential Asset
(Liability)
(mmbbl) ($ per bbl) ($ in millions)
Oil:
Swaps:
Short-term 15
$ 50.95
$ —
$ —
$ —
$ (16 )
Long-term 3
$ 50.93
$ —
$ —
$ —
(1 )
Three Way Collars:
Short-term 1
$ —
$ 55.00
$39.15 / $47.00 $ —
$ (1 )
Long-term 1
$ —
$ 55.00
$39.15 / $47.00 $ —
(1 )
Call Options (sold):
Short-term 1
$ —
$ 71.00
$ —
$ —
—
Call Swaptions:
Short-term 1
$ 52.87
$ —
$ —
$ —
$ (4 )
Long-term 1
$ 52.87
$ —
$ —
$ —
(3 )
Basis Protection Swaps:
Short-term 3
$ —
$ —
$ —
$ 2.94
(1 )
Total Oil (27 )
(tbtu) ($ per mmbtu)
Natural Gas:
Swaps^(a):

Short-term 576
$ 3.15
$ —
$ —
$ —
42
Long-term 120
$ 3.00
$ —
$ —
$ —
(4 )
Collars:
Short-term 59
$ —
$ 3.42
$ 3.10
$ —
7
Long-term 12
$ —
$ 3.25
$ 3.00
$ —
1
Call Options (sold):
Short-term 61
$ —
$ 6.89
$ —
$ —
(5 )
Long-term 60
$ —
$ 10.43
$ —
$ —
(2 )
Basis Protection Swaps:
Short-term 24
$ —
$ —
$ —
$ (0.70 ) (1 )
Long-term 2
$ —
$ —
$ —
$ (0.77 ) —
Total Natural Gas 38
(mmgal) ($ per mgal)
NGL:
Propane Swaps
Short-term 15
$ 0.76
$ —
$ —
$ —
(2 )
Total NGL
Total Estimated Fair Value $ 9


~~(a)~~	~~This amount includes a sold option to enhance the swap price at an average price~~prices would decrease the valuation of ~~$3.40 / mmbtu covering 44 tbtu, included in the sold call options.~~

Table of ~~the cross currency swaps were recorded on the condensed consolidated balance sheet as a liability of $73 million as of December 31, 2016.~~Contents

~~In addition to the open derivative positions disclosed above, as of~~ ~~September 30, 2017~~, we had $61 million of net derivative losses related to settled contracts for future production periods that will be recorded within oil, natural gas and NGL sales as realized gains (losses) on derivatives once they are transferred from either accumulated other comprehensive income or unrealized gains (losses) on derivatives in the month of related production, based on the terms specified in the original contract as noted below.

September 30,
2017
($ in millions)
Short-term $ 2
Long-term (63 )
Total $ (61 )

~~The table below reconciles the changes in fair value of our oil and~~ natural gas derivatives ~~during~~by approximately $256 million. A 10% decrease in forward natural gas prices would increase the ~~Current Period. Of~~valuation of natural gas derivatives by approximately $260 million. A 10% increase in forward oil prices would decrease the valuation of oil derivatives by approximately $8 million. A 10% decrease in forward oil prices would increase the valuation of oil derivatives by approximately $9 ~~million fair value asset as~~million. See Note 1 1 of ~~September 30, 2017, a $20 million asset relates~~the notes to ~~contracts maturing~~our condensed consolidated financial statements included in ~~the next 12 months and an $11 million liability relates to contracts maturing after 12 months. All~~Item 1 of Part I of this report for further information on our open derivative ~~instruments as of~~ ~~September 30, 2017~~ ~~are expected to mature by December 31, 2020.~~

September 30,
2017
($ in millions)
Fair value of contracts outstanding, as of January 1, 2017 $ (504 )
Change in fair value of contracts 477
Contracts realized or otherwise settled 36
Fair value of contracts outstanding, as of September 30, 2017 $ 9
positions.

Interest Rate ~~Derivatives~~Risk

The table below presents principal cash flows and related weighted average interest rates by expected maturity dates, using the earliest demand repurchase date for contingent convertible senior notes. As of September 30, 2017, we had total debt of $9.775 billion, including $7.250 billion of fixed rate debt at interest rates averaging 6.87% and $2.525 billion of floating rate debt at anOur exposure to interest rate changes relates primarily to borrowings under our New Credit Facility for the first three months of ~~6.47%.~~

Years of Maturity
2017 2018 2019 2020 2021 Thereafter Total
($ in millions)
Liabilities:
Debt – fixed rate^(a)
$ —
$ 52
$ —
$ 852
$ 820
$ 5,526
$ 7,250
Average interest rate — % 6.42 % — % 6.71 % 5.88 % 7.04 % 6.87 %
Debt – variable rate $ —
$ —
$ 1,025
$ —
$ 1,500
$ —
$ 2,525
Average interest rate — % — % 3.22 % — % 8.69 % — % 6.47 %


~~(a)~~	~~This amount excludes the premium, discount and deferred financing costs included in debt of $122 million and interest rate derivatives of $2 million.~~

~~Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments~~2023 and the ~~interest rate we pay~~Exit Credit Facility for the first three months of 2022. Interest is payable on borrowings under ~~our revolving~~each respective credit facility ~~term loan and our~~based on floating ~~rate senior notes. All of our other indebtedness is fixed rate and, therefore, does not expose us to the risk of fluctuations in earnings or cash flow due to changes in market interest~~ rates. ~~However, changes in interest rates do affect the fair value of our fixed-rate debt.~~

From time to time, we enter into interest rate derivatives, including fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes and floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our revolving credit facility borrowings. As of ~~September 30, 2017, there were no interest rate derivatives outstanding.~~

See ~~TABLE OF CONTENTS~~Note

~~As of~~ ~~September 30, 2017~~, we had $10 million of net gains related to settled derivative contracts that will be recorded within interest expense as realized gains or losses once they are transferred from our senior note liability or within interest expense as unrealized gains or losses over the remaining six year term of our related senior notes.

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

~~Foreign Currency Derivatives~~

~~During the Current Period, both our 6.25% Euro-denominated Senior Notes due 2017 and cross currency swaps for the same principal amount matured. Upon maturity~~4 of the notes ~~the counterparties paid us €246 million and~~to our condensed consolidated financial statements included in Item 1 of Part 1 of this report for additional information. As of March 31, 2023, we paid the counterparties $327 million. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. The swaps were designated as cash flow hedges and, because they were entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value did not ~~impact earnings. The fair values~~have any outstanding borrowings under our New Credit Facility.


ITEM 4.			Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of ~~Chesapeake’s~~our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based on that evaluation, our Chief Executive Officer and ~~our~~ Chief Financial Officer concluded as of March 31, 2023 that our disclosure controls and procedures were not effective as of September 30, 2017, because of the material weakness in our internal control over financial reporting described in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8 of Part II of our Annual Report on Form 10-K for the year ended December 31, 2016.

~~Remediation Plan for the Material Weakness~~

Our management is actively engaged in remediation efforts to address the material weakness identified. Specifically, our management is in the process of implementing controls related to reviewing the configuration of the basis price differential calculations, including a control activity to verify any subsequent changes are appropriately reviewed and that the interface control is designed to validate the data at an appropriately disaggregated level. Our management believes that these actions will remediate the material weakness in internal control over financial reporting.effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the ~~quarter ended September 30, 2017, which~~period covered by this quarterly report on Form 10-Q that materially affected, or ~~were~~are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION


ITEM 1.			Legal Proceedings

Business Operations and Litigation and Regulatory Proceedings

We are involved in various pre-petition lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. The ~~Company is~~majority of these prepetition legal proceedings were settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court, together with actions seeking to collect pre-petition indebtedness or to exercise control over the property of the Company’s bankruptcy estates. Any allowed claim related to such litigation will be treated in accordance with the Plan. We were involved in a number of litigation and regulatory proceedings ~~including those described below.~~as of the Petition Date. Many of these proceedings ~~are~~were in early stages, and many of them ~~seek or may seek~~sought damages and penalties, the amount of which is currently indeterminate. See Note 45 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings. Commencement of the Chapter 11 Cases automatically stayed the proceedings and actions against us that are referred to above. 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.

~~Regulatory~~Environmental Contingencies

The nature of the natural gas and ~~Related Proceedings.~~ ~~The Company has received DOJ, U.S. Postal Service~~oil business carries with it certain environmental risks for us and ~~state subpoenas seeking information~~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 Company’s royalty payment practices. On September 19, 2017, the DOJ informed Chesapeake that it had concluded its investigation with no action taken on these matters and matters related to the purchase and leaseextent of ~~oil and natural gas rights. Chesapeake has engaged in discussions with the U.S. Postal Service and state agency representatives and continues to respond to related subpoenas and demands.~~

~~Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege,~~an identified environmental concern, we may, among other things, ~~that we used below-market prices, made improper deductions, used improper measurement techniques and/~~exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or ~~entered into arrangements with affiliates that resulted in underpayment of royalties in connection with~~agree to assume liability for the production and sale of natural gas and NGL. Plaintiffs have varying royalty provisions in their respective leases, oil and gas law varies from state to state, and royalty owners and producers differ in their interpretationremediation of the legal effect of lease provisions governing royalty calculations. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. Weproperty.

Other Matters

Based on management’s current assessment, we are currently defending lawsuits seeking damages with respect to underpayment of royalties in various states, including, but not limited to, Texas, Pennsylvania, Ohio, Oklahoma, Kentucky, Louisiana and Arkansas. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class.

Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the Company’s divestiture of substantially all of its midstream business and most of its gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights. One of the cases includes claims of intentional interference with contractual relations and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources.

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

~~Environmental Proceedings~~

Our subsidiary Chesapeake Appalachia, LLC (CALLC) is engaged in discussions with the EPA, the U.S. Army Corps of Engineers and the Pennsylvania Department of Environmental Protection (PADEP) regarding potential violations of the permitting requirements of the federal Clean Water Act, the Pennsylvania Clean Streams Law and the Pennsylvania Dam Safety and Encroachments Act in connection with the placement of dredge and fill material during construction of certain sites in Pennsylvania. CALLC identified the potential violations in connection with an internal review of its facilities siting and construction processes and voluntarily reported them to the regulatory agencies. Resolution of the matter may result in monetary sanctions of more than $100,000.

We are also in discussions with PADEP regarding gas migration in the vicinity of certain of our wells in Bradford 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, we anticipate making a donation of $300,000 to the PADEP’s well plugging fund.

On December 27, 2016, we received a Finding of Violation from the EPA alleging violations of the Clean Air Act at a number of locations in Ohio. We have exchanged information with the EPA and are engaged in discussions aimed at resolving the allegations. Resolution of the matter may result in monetary sanctions of more than $100,000.

We are named as a defendant in a number of putative class actions and one mass tort action in Oklahoma alleging that we and several other companies have engaged in activities that have caused earthquakes. These actions seek, among other things, compensation for injury to real property, reimbursement of insurance premiums, and punitive damages.


ITEM 1A.			Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock ~~preferred stock or senior notes~~ are described under “Risk Factors” in Item 1A of our ~~2016~~202 2 Form ~~10-K.~~10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.


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

~~The following table presents information about repurchases~~Repurchases of Equity Securities

On December 2, 2021, we announced that our Board of Directors authorized the repurchase of up to $1.0 billion in aggregate value of our common stock and/or warrants from time to time. In June 2022, our Board of Directors authorized an increase in the size of the share repurchase program from $1.0 billion to $2.0 billion in aggregate value of our common stock and/or warrants. The repurchase authorization permits repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, compliance with the Company’s debt agreements and other appropriate factors. The share repurchase program expires on December 31, 2023. The following table provides information regarding purchases of our common stock made by us during the quarter ended ~~September 30, 2017:~~March 31, 2023.


Period	Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)
January 1 - January 31	—	$	—	—	$	927
February 1 - February 28	—	$	—	—	$	927
March 1 - March 31	792,543	$	74.95	792,543	$	867
Total	792,543	$	74.95	792,543

Period
Total
Number
of Shares
Purchased^(a)

Average
Price
Paid
Per
Share^(a)

Total Number
of Shares
Purchased as
Part of
Publicly
Announced
Plans or
Programs

Maximum
Approximate
Dollar Value
of Shares
That May Yet
Be Purchased
Under
the Plans
or Programs^(b)
($ in millions)
July 1, 2017 through July 31, 2017 5,173
$ 4.82
—
$ 1,000
August 1, 2017 through August 31, 2017 —
$ —
—
$ 1,000
September 1, 2017 through September 30, 2017 —
$ —
—
$ 1,000
Total 5,173
$ 4.82
—


~~(a)~~	~~Includes shares of common stock purchased on behalf of Chesapeake’s deferred compensation plan related to participant deferrals and Company matching contributions.~~


~~(b)~~	In December 2014, Chesapeake’s Board of Directors authorized the repurchase of up to $1 billion of our common stock from time to time. The repurchase program does not have an expiration date. As of September 30, 2017, there have been no repurchases under the program.


ITEM 3.			Defaults Upon Senior Securities

~~Not applicable.~~

None.


ITEM 4.			Mine Safety Disclosures

~~Not applicable.~~

The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Form 10-Q. On March 20, 2023, we divested our mining assets to WildFire Energy I LLC.


ITEM 5.			Other Information

Not applicable.

Fifth Amended Joint Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates Pursuant to Chapter 11 of the Bankruptcy Code (Exhibit A of the Confirmation Order).


ITEM 6.			Exhibits

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

INDEX OF EXHIBITS

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed or

Furnished

Herewith

2.1

8-K

001-13726

2.1

1/19/2021

2.2

Agreement and Plan of Merger, dated as of August 10, 2021, by and among Chesapeake Energy Corporation, Hannibal Merger Sub, Inc., Hannibal Merger Sub, LLC, Vine Energy Inc. and Vine Energy Holdings LLC.

8-K

001-13726

2.1

8/11/2021

2.3

Partnership Interest Purchase Agreement by and among The Jan & Trevor Rees-Jones Revocable Trust, Rees-Jones Family Holdings, LP, Chief E&D Participants, LP, and Chief E&D (GP) LLC (collectively, as Sellers) and Chesapeake Energy Corporation and its affiliates, dated as of January 24, 2022.

10-K

001-13726

10.36

2/24/2022

2.4

Membership Interest Purchase Agreement by and among Radler 2000 Limited Partnership and Tug Hill, Inc., together as Sellers, and Chesapeake Energy Corporation and its affiliates, dated as of January 24, 2022.

10-K

001-13726

10.37

2/24/2022

2.5

10-K

001-13726

10.38

2/24/2022

3.1

Second Amended and Restated Certificate of Incorporation of Chesapeake Energy Corporation.

8-K

001-13726

3.1

2/9/2021

3.2

Second Amended and Restated Bylaws of Chesapeake Energy Corporation.

8-K

001-13726

3.2

2/9/2021

31.1

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

31.2

Mohit Singh, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

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

32.2

Mohit Singh, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

95.1

Mine Safety Disclosure.

101 INS

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

Incorporated by Reference
Filed or Furnished
Herewith
Exhibit
Number Exhibit Description Form SEC File
Number Exhibit Filing Date
3.1.1
Chesapeake’s Restated Certificate of Incorporation.
10-Q 001-13726 3.1.1 8/3/2017

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

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

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

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

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

4.1
Indenture dated as of April 24, 2014, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Deutsche Bank Trust Company Americas, as trustee.
8-K 001-13726 4.1 4/29/2014

4.2
Sixth Supplemental Indenture dated as of December 20, 2016 to Indenture dated as of April 24, 2014 with respect to 8.00% Senior Notes due 2025.
8-K 001-13726 4.2 12/20/2016

4.3
Seventh Supplemental Indenture dated as of June 6, 2017 to Indenture dated as of April 24, 2014 with respect to 8.00% Senior Notes due 2027 (includes Form of 8.00% Senior Notes as Exhibit A).
8-K 001-13726 4.2 6/7/2017

4.4
Registration Rights Agreement, dated as of October 12, 2017, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Morgan Stanley & Co. LLC with respect to 8.00% Senior Notes due 2025.
8-K 001-13726 4.4 10/12/2017

4.5
Registration Rights Agreement, dated as of October 12, 2017, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Morgan Stanley & Co. LLC with respect to 8.00% Senior Notes due 2027.
8-K 001-13726 4.5 10/12/2017

10.1
Employment Agreement dated as of August 29, 2017 between William Buergler and Chesapeake Energy Corporation.
8-K 001-13726 10.1 9/1/2017

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed or

Furnished

Herewith

101 SCH

Inline XBRL Taxonomy Extension Schema Document.

101 CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101 DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document.

101 LAB

Inline XBRL Taxonomy Extension Labels Linkbase Document.

101 PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

Incorporated by Reference
Filed or Furnished
Herewith
Exhibit
Number Exhibit Description Form SEC File
Number Exhibit Filing Date
10.2
Form of Indemnity Agreement for officers and directors of Chesapeake and its subsidiaries.
8-K 001-13726 10.3 6/27/2012

10.3
Purchase Agreement, dated September 27, 2017, by and among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Morgan Stanley & Co. LLC, as representative of the initial purchasers named therein, relating to the private placement of the 8.00% Senior Notes due 2025 and 8.00% Senior Notes due 2027.
8-K 001-13726 10.1 9/28/2017

12
Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends.
X

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

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

32.1
Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
X

32.2
Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
X

101.INS XBRL Instance Document. X

101.SCH XBRL Taxonomy Extension Schema Document. X

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document. X

101.DEF XBRL Taxonomy Extension Definition Linkbase Document. X

101.LAB XBRL Taxonomy Extension Labels Linkbase Document. X

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document. X