SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

California Resources Corporation

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☑ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☑ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act:

Large Accelerated Filer

☑☐

Accelerated Filer

☐

Non-Accelerated Filer

☐☑

Smaller Reporting Company

☐☑

Emerging Growth Company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☑ No


~~Shares of common stock outstanding as of June 30, 2020~~			~~49,453,297~~

* On July 16, 2020, CRC's common stock trading underIndicate by check mark whether the symbol "CRC" was delisted from the New York Stock Exchange (NYSE). Effective July 17, 2020, CRC’s common stock was quoted on the OTC Pink Market under the symbol “CRCQQ”. The delisting of the common stock from the NYSE underregistrant has filed all documents and reports required to be filed by Section ~~12(b)~~12, 13 or 15(d) of the Securities Exchange Act of 1934 ~~(Exchange Act) will be effective at~~subsequent to the ~~opening~~distribution of ~~business on August 11, 2020. Upon deregistration~~securities under a plan confirmed by a court. ☑ Yes ☐ No

Indicate the number of shares outstanding for each of the issuer's classes of common stock, ~~under Section 12(b)~~as of the ~~Exchange Act, the~~last practicable date.

The number of shares of common stock ~~will remain registered under Section 12(g)~~outstanding as of ~~the Exchange Act.~~April 30, 2021 was 83,319,660.

California Resources Corporation and Subsidiaries

PART I FINANCIAL INFORMATION

Item 1Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020

June 30, December 31,
2020 2019
CURRENT ASSETS
Cash $ 126 $ 17
Trade receivables 132 277
Inventories 61 67
Other current assets, net 84 130
Total current assets 403 491
PROPERTY, PLANT AND EQUIPMENT 22,914 22,889
Accumulated depreciation, depletion and amortization (18,465) (16,537)
Total property, plant and equipment, net 4,449 6,352
OTHER ASSETS 78 115
TOTAL ASSETS $ 4,930 $ 6,958

CURRENT LIABILITIES
Current portion of long-term debt 5,083 100
Current portion of deferred gain and issuance costs, net 125 —
Accounts payable 196 296
Accrued liabilities 355 313
Total current liabilities 5,759 709
LONG-TERM DEBT — 4,877
DEFERRED GAIN AND ISSUANCE COSTS, NET — 146
OTHER LONG-TERM LIABILITIES 719 720
MEZZANINE EQUITY
Redeemable noncontrolling interests 828 802
EQUITY
Preferred stock (20 million shares authorized at $0.01 par value) 0 shares outstanding at June 30, 2020 and December 31, 2019 — —
Common stock (200 million shares authorized at $0.01 par value) outstanding shares (June 30, 2020 - 49,453,297 and December 31, 2019 - 49,175,843) — —
Additional paid-in capital 5,008 5,004
Accumulated deficit (7,437) (5,370)
Accumulated other comprehensive loss (23) (23)
Total equity attributable to common stock (2,452) (389)
Equity attributable to noncontrolling interests 76 93
Total equity (2,376) (296)
TOTAL LIABILITIES AND EQUITY $ 4,930 $ 6,958


	Successor
	March 31,		December 31,
	2021		2020
CURRENT ASSETS
Cash	$	130	$	28
Trade receivables	201		177
Inventories	59		61
Other current assets	71		63
Total current assets	461		329
PROPERTY, PLANT AND EQUIPMENT	2,711		2,689
Accumulated depreciation, depletion and amortization	(86)		(34)
Total property, plant and equipment, net	2,625		2,655
OTHER ASSETS	94		90
TOTAL ASSETS	$	3,180	$	3,074


CURRENT LIABILITIES



Accounts payable	213		212
Accrued liabilities	409		261
Total current liabilities	622		473
LONG-TERM DEBT, NET	588		597

OTHER LONG-TERM LIABILITIES	889		822



STOCKHOLDERS' EQUITY
Preferred stock (20 shares authorized at $0.01 par value) 0 shares outstanding at March 31, 2021 and December 31, 2020	0		0
Common stock (200 shares authorized at $0.01 par value) outstanding shares (83.3 at March 31, 2021 and December 31, 2020)	1		1
Additional paid-in capital	1,270		1,268
Accumulated deficit	(217)		(123)
Accumulated other comprehensive loss	(8)		(8)
Total equity attributable to common stock	1,046		1,138
Equity attributable to noncontrolling interests	35		44
Total stockholders' equity	1,081		1,182
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,180	$	3,074

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

For the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~

Three months ended
June 30, Six months ended
June 30,
2020 2019 2020 2019
REVENUES
Oil and natural gas sales $ 245 $ 578 $ 675 $ 1,179
Net derivative (loss) gain from commodity contracts (4) 21 75 (68)
Other revenue 35 54 99 232
Total revenues 276 653 849 1,343
COSTS
Production costs 127 230 319 463
General and administrative expenses 69 79 129 162
Depreciation, depletion and amortization 88 121 207 239
Asset impairments — — 1,736 —
Taxes other than on income 38 36 79 77
Exploration expense 2 10 7 20
Other expenses, net 67 55 136 203
Total costs 391 531 2,613 1,164
OPERATING (LOSS) INCOME (115) 122 (1,764) 179
NON-OPERATING (LOSS) INCOME
Interest and debt expense, net (85) (98) (172) (198)
Net gain on early extinguishment of debt — 20 5 26
Other non-operating expenses (47) (3) (61) (10)
(LOSS) INCOME BEFORE INCOME TAXES (247) 41 (1,992) (3)
Income tax — — — —
NET (LOSS) INCOME (247) 41 (1,992) (3)
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
Mezzanine equity (30) (29) (60) (57)
Equity 6 — (15) 5
Net income attributable to noncontrolling interests (24) (29) (75) (52)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK $ (271) $ 12 $ (2,067) $ (55)
Net (loss) income attributable to common stock per share
Basic $ (5.47) $ 0.25 $ (41.84) $ (1.13)
Diluted $ (5.47) $ 0.24 $ (41.84) $ (1.13)


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
REVENUES
Oil, natural gas and NGL sales	$	432	$	430
Net derivative (loss) gain from commodity contracts	(213)		79
Trading revenue	98		45
Electricity sales	33		13
Other revenue	13		6
Total revenues	363		573

COSTS
Operating costs	164		192
General and administrative expenses	48		60
Depreciation, depletion and amortization	52		119
Asset impairments	3		1,736
Taxes other than on income	40		41
Exploration expense	2		5
Trading costs	61		24
Electricity cost of sales	24		16
Transportation costs	12		13
Other expenses, net	30		16
Total costs	436		2,222

OPERATING LOSS	(73)		(1,649)

NON-OPERATING (LOSS) INCOME
Reorganization items	(2)		0
Interest and debt expense, net	(13)		(87)
Net (loss) gain on early extinguishment of debt	(2)		5
Gain on asset divestitures	2		0
Other non-operating expenses	(1)		(14)
LOSS BEFORE INCOME TAXES	(89)		(1,745)
Income tax	0		0
NET LOSS	(89)		(1,745)

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
Mezzanine equity	0		(30)
Stockholders' equity	(5)		(21)
Net income attributable to noncontrolling interests	(5)		(51)
NET LOSS ATTRIBUTABLE TO COMMON STOCK	$	(94)	$	(1,796)

Net loss attributable to common stock per share
Basic	$	(1.13)	$	(36.43)
Diluted	$	(1.13)	$	(36.43)

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Comprehensive Income (Loss)

For the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~

Three months ended
June 30, Six months ended
June 30,
2020 2019 2020 2019
Net (loss) income $ (247) $ 41 $ (1,992) $ (3)
Net income attributable to noncontrolling interests (24) (29) (75) (52)
Other comprehensive income:
Reclassification of realized losses on pension and postretirement benefits to income^(a)
— 1 — 1
Comprehensive (loss) income attributable to common stock $ (271) $ 13 $ (2,067) $ (54)

^(a)


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
Net loss	$	(89)	$	(1,745)
Net income attributable to noncontrolling interests	(5)		(51)


Comprehensive loss attributable to common stock	$	(94)	$	(1,796)

~~NaN associated tax for the three and six months ended June 30, 2020 and 2019. See~~ ~~Note 10 Pension and Postretirement Benefit Plans~~ ~~for additional information.~~

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Equity

For the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020

Three months ended June 30, 2020
Additional Paid-in Capital Accumulated Deficit Accumulated Other
Comprehensive
Loss Equity Attributable to Common Stock Equity Attributable to Noncontrolling Interests Total
Equity
Balance, March 31, 2020 $ 5,006 $ (7,166) $ (23) $ (2,183) $ 88 $ (2,095)
Net loss — (271) — (271) (6) (277)
Distributions to noncontrolling interest holders — — — — (6) (6)
Share-based compensation, net 2 — — 2 — 2
Balance, June 30, 2020 $ 5,008 $ (7,437) $ (23) $ (2,452) $ 76 $ (2,376)

Net (loss) income(a)


	Three months ended March 31, 2020 (Predecessor)
	Common Stock		Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity		Redeemable Noncontrolling Interests(b)
Balance, December 31, 2019	$	0	$	5,004	$	(5,370)	$	(23)	(389)		$	93	$	(296)	$	802
Net (loss) income(a)	—		—		(1,796)		—		(1,796)		21		(1,775)		30
Contributions from noncontrolling interest holders			—		—		—		—				—		2
Distributions to noncontrolling interest holders	—		—		—		—		—		(26)		(26)		(18)
Share-based compensation, net	—		2		—		—		2		—		2		—






Balance, March 31, 2020	$	0	$	5,006	$	(7,166)	$	(23)	$	(2,183)	$	88	$	(2,095)	$	816

(a)For the three months ended March 31, 2020, we allocated $51 million of net income to noncontrolling interest holders, of which $21 million was included in stockholders' equity and $30 million was included in mezzanine equity on our condensed consolidated balance sheet. The ~~above tables exclude amounts related~~remaining net loss of $1,796 million for the three months ended March 31, 2020 was attributed to ~~redeemable~~holders of our common stock and included in stockholders' equity on our condensed consolidated balance sheet. For the three months ended March 31, 2021, we allocated $5 million of net income to noncontrolling interest holders, with the remaining $94 million of net loss attributed to holders of our common stock, both of which were included in stockholders' equity on our condensed consolidated balance sheet.

(b)Redeemable noncontrolling interests are reported in mezzanine ~~equity.~~equity on our condensed consolidated balance sheets in Predecessor periods. See Note 67 Joint Ventures for more ~~information.~~information about our noncontrolling interests in the Ares and Elk Hills Carbon joint ventures.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of ~~Equity~~Cash Flows

For the three ~~and six~~months ended ~~June 30, 2019~~March 31, 2021 and 2020

Three months ended June 30, 2019
Additional Paid-in Capital Accumulated Deficit Accumulated Other
Comprehensive
Loss Equity Attributable to Common Stock Equity Attributable to Noncontrolling Interests Total
Equity
Balance, March 31, 2019 $ 4,989 $ (5,409) $ (6) $ (426) $ 137 $ (289)
Net loss — 12 — 12 — 12
Contributions from noncontrolling interest holders, net — — — — — —
Distributions to noncontrolling interest holders — — — — (8) (8)
Issuance of common stock — — — — — —
Other comprehensive income — 1 1 — 1
Share-based compensation, net 5 — — 5 — 5
Balance, June 30, 2019 $ 4,994 $ (5,397) $ (5) $ (408) $ 129 $ (279)

Six months ended June 30, 2019
Additional Paid-in Capital Accumulated Deficit Accumulated Other
Comprehensive
Loss Equity Attributable to Common Stock Equity Attributable to Noncontrolling Interests Total
Equity
Balance, December 31, 2018 $ 4,987 $ (5,342) $ (6) $ (361) $ 114 $ (247)
Net loss — (55) — (55) (5) (60)
Contributions from noncontrolling interest holders, net — — — — 49 49
Distributions to noncontrolling interest holders — — — — (29) (29)
Other comprehensive income — — 1 1 — 1
Share-based compensation, net 7 — — 7 — 7
Balance, June 30, 2019 $ 4,994 $ (5,397) $ (5) $ (408) $ 129 $ (279)

~~Note: The above tables exclude amounts related to redeemable noncontrolling interests reported in mezzanine equity. See~~ ~~Note 6Joint Ventures~~ ~~for more information.~~


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
CASH FLOW FROM OPERATING ACTIVITIES
Net loss	$	(89)	$	(1,745)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	52		119
Asset impairments	3		1,736
Net derivative loss (gain) from commodity contracts	213		(79)
Net (payments) proceeds from settled commodity derivatives	(39)		98
Net loss (gain) on early extinguishment of debt	2		(5)
Amortization of deferred gain	0		(17)
Gain on asset divestiture	(2)		0



Other non-cash charges to income, net	7		8
Changes in operating assets and liabilities, net	0		113
Net cash provided by operating activities	147		228

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(27)		(30)
Changes in accrued capital investments	5		(19)
Proceeds from asset divestitures	2		41

Other	0		(4)
Net cash used in investing activities	(20)		(12)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from Revolving Credit Facility	16		0
Repayments of Revolving Credit Facility	(115)		0
Proceeds from 2014 Revolving Credit Facility	0		449
Repayments of 2014 Revolving Credit Facility	0		(459)
Proceeds from Senior Notes	600		0
Debt repurchases	0		(3)
Debt issuance costs	(12)		0
Repayment of Second Lien Term Loan	(200)		0
Repayment of EHP Notes	(300)		0
Repayment of 2020 Senior Notes	0		(100)
Contributions from noncontrolling interest holders	0		2
Distributions paid to noncontrolling interest holders	(14)		(44)

Shares cancelled for taxes	0		(1)
Net cash used in financing activities	(25)		(156)
Increase in cash	102		60
Cash—beginning of period	28		17
Cash—end of period	$	130	$	77

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

~~Condensed Consolidated Statements of Cash Flows~~

~~For the six months ended June 30, 2020 and 2019~~

Six months ended
June 30,
2020 2019
CASH FLOW FROM OPERATING ACTIVITIES
Net loss $ (1,992) $ (3)
Adjustments to reconcile net loss to net cash provided by
operating activities:
Depreciation, depletion and amortization 207 239
Asset impairments 1,736 —
Net derivative (gain) loss from commodity contracts (75) 68
Net proceeds from settled commodity derivatives 103 28
Net gain on early extinguishment of debt (5) (26)
Amortization of deferred gain (33) (36)
Dry hole expenses — 7
Other non-cash charges to income, net 22 47
Changes in operating assets and liabilities, net 130 (52)
Net cash provided by operating activities 93 272
CASH FLOW FROM INVESTING ACTIVITIES
Capital investments (33) (271)
Changes in capital investment accruals (28) (57)
Asset divestitures 41 165
Acquisitions — (2)
Other (7) (5)
Net cash used in investing activities (27) (170)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from 2014 Revolving Credit Facility 795 1,274
Repayments of 2014 Revolving Credit Facility (582) (1,289)
Debt repurchases (3) (59)
2020 Senior Notes payment (100) —
Contributions from noncontrolling interest holders, net 2 49
Distributions paid to noncontrolling interest holders (68) (65)
Issuance of common stock — 1
Shares canceled for taxes (1) (3)
Net cash provided by (used in) financing activities 43 (92)
Increase in cash 109 10
Cash—beginning of period 17 17
Cash—end of period $ 126 $ 27

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

~~CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES~~

Notes to the Condensed Consolidated Financial Statements

~~June 30, 2020~~March 31, 2021

NOTE 1 BASIS OF PRESENTATION

We are an independent oil and natural gas exploration and production company operating properties exclusively within California. ~~We were incorporated in Delaware and became a publicly traded company on December 1, 2014.~~

Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.

~~Voluntary Petitions for Relief Under Chapter 11 of the Bankruptcy Code~~

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code (Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court). The Chapter 11 cases filed by us (Chapter 11 Cases) are being jointly administered under the caption ~~In re California Resources Corporation, et al., Case No. 20-33568 (DRJ). On July 24, 2020, we filed a Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code with the Bankruptcy Court.~~

We continue to operate our business as “debtors-in-possession” (DIP) under the jurisdiction of the Bankruptcy Court and in accordance with the Bankruptcy Code. To ensure our ability to continue operating in the ordinary course of business and to minimize the effect of the Chapter 11 Cases on our employees, vendors and customers, we filed motions for customary “first day” relief with the Bankruptcy Court. On July 17, 2020, the Bankruptcy Court entered interim or final orders that included authorizing payments of pre-petition liabilities with respect to certain employee compensation and benefits, taxes, royalties, certain essential vendor payments and insurance and surety obligations. On July 21, 2020, the Bankruptcy Court approved on a final basis an order designed to assist us in preserving certain tax attributes. This order established the procedures that certain stockholders and potential stockholders will be required to comply with regarding transfers of, or declarations of worthlessness with respect to, our common stock as well as certain notice obligations. On July 22, 2020, the Bankruptcy Court approved on an interim basis a motion authorizing us to enter into DIP financing.

The commencement of the Chapter 11 Cases constitutes an event of default that accelerated our obligations under the following agreements: (i) Credit Agreement, dated as of September 24, 2014, among JPMorgan Chase Bank, N.A., as administrative agent, and the lenders that are party thereto (2014 Revolving Credit Facility), (ii) Credit Agreement, dated as of August 12, 2016, among The Bank of New York Mellon Trust Company, N.A., as collateral and administrative agent, and the lenders that are party thereto (2016 Credit Agreement), (iii) Credit Agreement, dated as of November 17, 2017, among The Bank of America Mellon Trust Company, N.A., as administrative agent, and the lenders that are party thereto (2017 Credit Agreement), and (iv) the indentures governing our 8% Senior Secured Second Lien Notes due 2022 (Second Lien Notes), 5.5% Senior Notes due 2021 (2021 Notes) and 6% Senior Notes due 2024 (2024 Notes). Additionally, other events of default, including cross-defaults, are present under these debt agreements. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against us, including exercising remedies as a result of any event of default. See ~~Note 5 Debt~~ ~~for additional details about our debt.~~

~~Restructuring Support Agreement~~

On July 15, 2020, we entered into a Restructuring Support Agreement which was subsequently amended on July 24, 2020 (RSA). This RSA contemplates a restructuring plan that establishes a reorganized company with a new capital structure. The transactions contemplated by the RSA plan include (i) entering into a senior secured superpriority DIP credit facility (Senior DIP Facility) in an aggregate principal amount of up to approximately $483 million, (ii) entering into a junior secured superpriority DIP term loan facility in an aggregate amount of $650 million, (iii) the implementation of financing upon emergence from bankruptcy, (iv) the issuance of new common stock, and (v) a $450 million equity rights offering, backstopped by certain parties to the RSA.

The following creditors have entered into the RSA: (i) lenders holding approximately 85% of the outstanding principal amount of loans under the 2017 Credit Agreement, (ii) creditors holding approximately 68% of the aggregate claims arising under the 2016 Credit Agreement, the Second Lien Notes, the 2021 Notes and the 2024 Notes, and (iii) one or more funds, investment vehicles and/or accounts managed or advised by Ares Management LLC (Ares) or its affiliates, including ECR Corporate Holdings L.P. (ECR).

The transactions contemplated by the RSA, if approved, will result in current holders of our common stock receiving no distribution on account of their claims or interests. No assurance can be given that the Bankruptcy Court will approve the terms proposed under the RSA.

~~Debtor-in-Possession Credit Agreements~~

On July 23, 2020, we entered into (1) a Senior Secured Superpriority DIP Credit Agreement with JP Morgan, as administrative agent, and certain other lenders (Senior DIP Credit Agreement) and (2) a Junior Secured Superpriority DIP Credit Agreement with Alter Domus, as administrative agent, and certain lenders (Junior DIP Credit Agreement). For more information on our debtor-in-possession credit agreements, see ~~Note 5 Debt.~~

~~Ares JV Settlement Agreement~~

On July 15, 2020, prior to the commencement of the Chapter 11 Cases, we and certain affiliates of Ares, including ECR, entered into a settlement and assumption agreement (Settlement Agreement). On July 17, 2020, the Bankruptcy Court entered an order approving the Settlement Agreement on an interim basis pending a final hearing. Upon entry of a final order by the Bankruptcy Court, we will be granted the right to acquire all of the equity interests of the Ares JV owned by ECR in exchange for secured notes, cash and common stock upon emergence from bankruptcy. We have also agreed to certain covenants and amendments to the Ares JV limited liability company agreement. The Settlement Agreement may be terminated in certain limited circumstances. For more information on the Ares JV, see ~~Note 6 Joint Ventures.~~

~~Ability to Continue as a Going Concern~~

We currently expect that our cash flows, cash on hand and financing available through our DIP credit agreements should provide sufficient liquidity during the pendency of the Chapter 11 Cases. However, for the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to a high degree of risks and uncertainty associated with the Chapter 11 proceedings. The outcome of the Chapter 11 Cases is also subject to a high degree of uncertainty and is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court, our creditors, and Ares. There can be no assurance that we will confirm and consummate the plan under the RSA or complete another plan of reorganization with respect to the Chapter 11 proceedings. There is substantial doubt that we can continue as a going concern if we are not able to complete the plan of reorganization contemplated by the RSA or another plan of reorganization as part of the Chapter 11 Cases.

~~For the duration of the Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 Cases. See~~ ~~Part II, Item 1A~~ – ~~Risk Factors, below for further discussion of these risks and risks related to our ability to continue as a going concern.~~

~~Basis of Presentation~~

The accompanying condensed consolidated financial statements have been prepared assuming we will continue as a going concern. These financial statements do not include any adjustments that might result from the outcome of our going concern uncertainty or the Chapter 11 Cases. Further, the Chapter 11 Cases could result in a change in the basis of our accounting, which may have a material effect on the carrying value of certain assets and liabilities.

In the opinion of our management, the accompanying unaudited financial statements contain all adjustments (consisting of normal recurring adjustments) necessary to fairly present our financial position, ~~as of June 30, 2020 and December 31, 2019 and the statements~~results of operations, comprehensive income, ~~(loss),~~ equity and cash flows for ~~the three and six months ended June 30, 2020 and 2019, as applicable.~~all periods presented. We have eliminated all significant intercompany transactions and accounts. We account for our share of oil and natural gas ~~exploration and development ventures,~~producing activities, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on our condensed consolidated ~~balance sheets, statements of operations, equity and cash flows.~~financial statements.

We have prepared this report in accordance with generally accepted accounting principles (GAAP) in the United States and the rules and regulations of the U.S. Securities and Exchange Commission applicable to interim financial information which permit the omission of certain disclosures to the extent they have not changed materially since the latest annual financial statements. We believe our disclosures are adequate to make the information presented not misleading. ~~This Form 10-Q~~

The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting policies and make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Actual results could differ. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of our condensed consolidated financial statements. These condensed consolidated financial statements should be read in conjunction with the ~~condensed~~ consolidated financial statements and ~~the~~ notes thereto in our Annual Report on Form 10-K for the year ended December 31, ~~2019.~~2020 (2020 Annual Report).

Restructuring and Organization Changes

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. On October 13, 2020, the Bankruptcy Court confirmed our joint plan of reorganization (the Plan) and we subsequently emerged from Chapter 11 proceedings on October 27, 2020. In connection with our emergence from bankruptcy, our Board of Directors was reconstituted in October 2020. On December 31, 2020, our former President, Chief Executive Officer and director Todd A. Stevens departed and Mark A. (Mac) McFarland was appointed as interim Chief Executive Officer in addition to his role as Chair of our Board of Directors. On March 22, 2021, the Board of Directors appointed Mr. McFarland as President and Chief Executive Officer on a permanent basis. On April 15, 2021, Tiffany (TJ) Thom Cepak replaced Mr. McFarland as the Chair of our Board of Directors. Mr. McFarland will continue to serve as a director.

In January 2021, we reduced the size of our management team and then realigned several functions in February 2021, which resulted in additional headcount and cost reductions. We recorded a restructuring charge of $14 million for the three months ended March 31, 2021, which is included in other expenses, net on our condensed consolidated statement of operations. As of March 31, 2021, our remaining liability for workforce reductions which occurred in 2020 and during the first quarter of 2021 is $16 million, which is included in accrued liabilities on our condensed consolidated balance sheet.

NOTE 2 ACCOUNTING AND DISCLOSURE CHANGES

Recently Adopted Accounting and Disclosure Changes

We qualified for and adopted fresh start accounting upon emergence from bankruptcy at which point we became a new entity for financial reporting purposes. We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 3 Fresh Start Accounting ~~Standards Board's~~ in our 2020 Annual Report for additional information on the terms of the Plan, our emergence from bankruptcy and application of fresh start accounting.

We adopted new ~~rules~~accounting guidance on current expected credit losses on January 1, 2020, using a modified retrospective approach to the first period in which the guidance iswas effective. The new rules ~~change~~changed the measurement of credit losses for financial assets and certain other instruments, including trade and other receivables with a right to receive cash, and require the use of a new forward-looking expected loss model that ~~will result~~results in the earlier recognition of an allowance for losses. The adoption of these new rules did not have a significant impact toon our condensed consolidated financial statements.

These rules apply to our trade receivables and joint interest billings to third-party customers. Credit exposure for each customer is monitored for outstanding balances and current activity. We actively manage our credit risk by selecting counterparties that we believe to be financially sound and continue to monitor their financial health. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified. We believe exposure to counterparty credit-related losses at June 30, 2020 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

NOTE 3 OTHER INFORMATION

~~Restricted cash~~ — Cash at June 30, 2020 included $21 million which was restricted under agreements to fund operating expenses at one of our joint ventures and hold for distributions to a joint venture (JV) partner. Cash at December 31, 2019 included $3 million, which was restricted for distributions to a JV partner.

Other current assets ~~net~~ — Other current assets ~~net as of June 30, 2020 and December 31, 2019~~ consisted of the following:

Net amounts due from joint interest partners^(a)

Derivative assets^(b)

~~(a)Both June 30, 2020 and December 31, 2019 balances included $19 million in an allowance for credit losses against the receivables from our joint interest partners.~~

~~(b)~~Derivative assets at June 30, 2020 included only commodity contracts held by the Benefit Street Partners joint venture (BSP JV). Derivative assets at December 31, 2019 included commodity contracts for our hedge positions and those held by the BSP JV.


	Successor
	March 31,		December 31,
	2021		2020
	(in millions)
Amounts due from joint interest partners	$	44	$	42
Amounts due from counterparties on derivative contracts	8		0
Prepaid expenses	18		20
Other	1		1
Other current assets	$	71	$	63

Accrued liabilities — Accrued liabilities ~~as of June 30, 2020 and December 31, 2019~~ consisted of the following:

Accrued employee-related costs^(a)

Accrued taxes other than on income^(b)

Accrued interest^(c)

~~(a)As of June 30, 2020, accrued employee-related costs declined $68 million primarily due to bonus, long term incentive and severance payments made to employees and former employees.~~

~~(b)~~Accrued taxes other than income increased $37 million as of June 30, 2020 primarily due to missed property tax payments in April 2020 as a result of the economic impact of Coronavirus Disease 2019 (COVID-19).

~~(c)Accrued interest increased $141 million as of June 30, 2020 primarily due to missed interest payments as described in~~ ~~Note 5 Debt~~.

~~(d)Other accrued liabilities declined $55 million as of June 30, 2020 primarily due to the timing of payments with joint interest partners and settlement payments.~~


	Successor
	March 31,		December 31,
	2021		2020
	(in millions)
Accrued employee-related costs	$	63	$	72
Accrued taxes other than on income	44		36
Asset retirement obligations	50		50
Accrued interest	10		1
Lease liability	10		7
Fair value of derivative contracts	151		50
Amounts due to counterparties on derivative contracts	44		21
Other	37		24
Accrued liabilities	$	409	$	261

Other long-term liabilities — Other long-term liabilities included ~~asset retirement obligations of $499 million and $489 million at June 30, 2020 and December 31, 2019, respectively. The remainder of~~ the ~~balance for each year consisted primarily of postretirement and pension benefit obligations, liabilities related to deferred compensation arrangements and lease liabilities.~~following:


	Successor
	March 31,		December 31,
	2021		2020
	(in millions)
Asset retirement obligations	$	546	$	547
Deferred compensation and postretirement	180		184
Lease liability	34		35
Fair value of derivative contracts	86		6
Amounts due to counterparties on derivative contracts	24		31
Other	19		19
Other long-term liabilities	$	889	$	822

Supplemental Cash Flow Information

We did 0t make U.S. federal and state income tax payments during the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 and ~~2019.~~2020. Interest paid, net of capitalized amounts, totaled ~~$51~~$2 million and ~~$219~~$45 million for the ~~six~~three months ended ~~June 30,~~March 31, 2021 and 2020, ~~and 2019,~~ respectively. Cash paid for reorganization items during the three months ended March 31, 2021 was $2 million.

Fair Value of Financial Instruments

The carrying amounts of cash and ~~other~~ on-balance sheet financial instruments, other than debt, approximate fair value. Refer to Note 5 Debt for the fair value of our debt. Refer to Note 14 Asset Impairments for impairment charges related to our long-lived assets.

Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods predominantly comprise oil and natural gas liquids (NGLs), which are valued at the lower of cost ~~and~~or net realizable value. Inventories, by category, are as ~~of June 30, 2020 and December 31, 2019 consisted of the following:~~follows:


	Successor
	March 31,		December 31,
	2021		2020
	(in millions)
Materials and supplies	$	57	$	58
Finished goods	2		3
Inventories	$	59	$	61

~~We have classified all our long-term debt as current due to events of default that occurred prior to June 30, 2020 and the commencement of the Chapter 11 Cases on July 15, 2020 as described below.~~

As of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, our long-term debt consisted of the ~~following credit agreements, Second Lien Notes and Senior Notes:~~following:

Outstanding Principal Interest Rate Security
June 30, 2020 December 31, 2019
Credit Agreements ($ in millions)
2014 Revolving Credit Facility $ 731 $ 518
LIBOR plus 3.25%-4.00%
ABR plus 2.25%-3.00%
Shared First-Priority Lien
2017 Credit Agreement 1,300 1,300
LIBOR plus 4.75%
ABR plus 3.75%
Shared First-Priority Lien
2016 Credit Agreement 1,000 1,000
LIBOR plus 10.375%
ABR plus 9.375%
First-Priority Lien
Second Lien Notes
Second Lien Notes 1,808 1,815 8% Second-Priority Lien
Senior Notes
5% Senior Notes due 2020 — 100 5% Unsecured
5.5% Senior Notes due 2021 100 100 5.5% Unsecured
6% Senior Notes due 2024 144 144 6% Unsecured
Total Debt $ 5,083 $ 4,977
Less: Current Portion of Long-Term Debt (5,083) (100)
Total Long-Term Debt $ — $ 4,877

~~Note: For a detailed description of our credit agreements, Second Lien Notes and Senior Notes, please see our most recent Form 10-K for the year ended December 31, 2019.~~


	Successor
	March 31,		December 31,
	2021		2020		Interest Rate	Maturity
	(in millions)

Revolving Credit Facility	$	0	$	99	LIBOR plus 3%-4% ABR plus 2%-3%	April 29, 2024

Second Lien Term Loan	0		200		LIBOR plus 9%-10.5% ABR plus 8%-9.5%	October 27, 2025

EHP Notes	0		300		6%	October 27, 2027
Senior Notes	600		0		7.125%	February 1, 2026
Principal Amount	$	600	$	599
Unamortized debt issuance costs	(12)		(2)
Long-term debt, net	$	588	$	597

The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the 2014 Revolving Credit Facility, 2016 Credit Agreement, 2017 Credit Agreement, and the indentures governing the Second Lien Notes, 2021 Notes and 2024 Notes, resulting in the automatic and immediate acceleration of all of our outstanding debt. Any efforts to enforce payment obligations related to the acceleration of our debt were automatically stayed immediately upon the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. See ~~Note 1 Basis of Presentation~~ ~~for more information on the Chapter 11 Cases.~~

~~Debtor-in-Possession Credit Agreements~~

On July 23, 2020, we entered into the Senior DIP Credit Agreement, which provides for the senior DIP facility in an aggregate principal amount of up to $483 million (Senior DIP Facility). The Senior DIP Facility includes a $250 million revolving facility which will be primarily used by us to (i) fund working capital needs and capital expenditures and additional letters of credit during the pendency of the Chapter 11 Cases and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Senior DIP Facility. Until the Bankruptcy Court enters a final order with respect to our DIP credit agreements, only $85 million of revolving borrowings are available. If the Bankruptcy Court enters a final order approving the Senior DIP Facility in its current form following a hearing on August 14, 2020, we expect the full remaining amount of the $250 million revolving facility to become available. The Senior DIP Facility also includes (a) a $150 million letter of credit facility which was used to deem letters of credit outstanding under the 2014 Revolving Credit Facility as issued under the Senior DIP Facility, and (b) $83 million of term loan borrowings which were used to repay a portion of the 2014 Revolving Credit Facility.

On July 23, 2020, we entered into the Junior DIP Credit Agreement, which provides for a junior DIP facility in an aggregate principal amount of $650 million (Junior DIP Facility). The proceeds of the Junior DIP Facility were used to (i) refinance in full all remaining obligations under the 2014 Revolving Credit Facility and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Junior DIP Facility.

The Senior DIP Credit Agreement and Junior DIP Credit Agreement both contain representations, warranties, and covenants that are customary for DIP facilities of their type, including certain milestones applicable to the Chapter 11 Cases, compliance with an agreed budget, hedging on not less than 25% of our share of expected crude oil production for a specified period, and other customary limitations on additional indebtedness, liens, asset dispositions, investments, restricted payments and other negative covenants, in each case subject to exceptions. Additionally, the Senior DIP Credit Agreement and Junior DIP Credit Agreement require us to maintain (i) minimum liquidity over a rolling four-week period of not less than $50 million, and (ii) minimum liquidity at all times of not less than $35 million. The Senior DIP Credit Agreement and Junior DIP Credit Agreement also contain customary events of default for facilities of their type, including failure to achieve the milestones and the occurrence of certain events in the Chapter 11 Cases. If an event of default occurs or is continuing, the applicable administrative agent may accelerate repayment of the indebtedness outstanding under the Senior DIP Facility or the Junior DIP Facility.

Borrowings under the Senior DIP Facility bear interest at a rate of LIBOR plus 4.5% for LIBOR loans and ABR plus 3.5% for alternative base rate loans. We also agreed to pay an upfront fee equal to 1.0% on the commitment amount of the Senior DIP Facility and quarterly commitment fees of 0.5% on the undrawn portion of the Senior DIP Facility.

~~Borrowings under the Junior DIP Facility bear interest at a rate of LIBOR plus 9.0% for LIBOR loans and ABR plus 8.0% for alternate base rate loans.We also agreed to pay an upfront fee equal to 1.0% of the commitment amount funded on the closing date and a fronting fee to a fronting lender.~~

~~Certain of our subsidiaries, including each of the debtors in the Chapter 11 Cases, have guaranteed all~~obligations under the Senior DIP Credit Agreement and Junior DIP Credit Agreement. To secure the obligations under the Senior DIP Credit Agreement and Junior DIP Credit Agreement, we have granted liens on substantially all of our assets, whether now owned or hereafter acquired.

~~The Senior DIP Facility and the Junior DIP Facility both mature on January 15, 2021.~~

~~Net Deferred Gain and Issuance Costs~~

~~As of June 30, 2020 and December 31, 2019, net deferred gain and issuance costs consisted of the following:~~

~~(a)~~Due to uncertainties at June 30, 2020 regarding default and the commencement of the Chapter 11 Cases on July 15, 2020, we have classified all our outstanding debt and associated deferred gain, unamortized debt issue costs and discounts as a current liability as of June 30, 2020. Refer to ~~Note 1 Basis of Presentation~~ ~~for more information on the Chapter 11 Cases.~~

~~Missed Interest Payments and Forbearance~~

On May 15, 2020, we did not make an interest payment of approximately $4 million on our 2024 Notes. The indenture governing the 2024 Notes provides for a 30-day grace period and the payment was made on June 12, 2020.

On May 29, 2020, we did not pay approximately $51 million in the aggregate of interest due under our 2017 Credit Agreement and 2016 Credit Agreement. Our failure to make those interest payments constituted events of default under the 2017 Credit Agreement, 2016 Credit Agreement and, as a result of cross default, under the 2014 Revolving Credit Facility.

On June 2, 2020, we entered into forbearance agreements (Forbearance Agreements) with (i) certain lenders of a majority of the outstanding principal amount of the loans under the 2014 Revolving Credit Facility, (ii) certain lenders of a majority of the outstanding principal amount of the loans under the 2016 Credit Agreement, and (iii) certain lenders of a majority of the outstanding principal amount of the loans under the 2017 Credit Agreement. Pursuant to the Forbearance Agreements, the lenders who are parties to the Forbearance Agreements agreed to forbear from exercising any remedies under the 2014 Revolving Credit Facility, 2016 Credit Agreement and 2017 Credit Agreement with respect to our failure to make the aforementioned interest payments, initially through June 14, 2020 and subsequently through July 15, 2020.

On June 15, 2020, we did not make an interest payment of approximately $72 million on our Second Lien Notes. The indenture governing the Second Lien Notes (Second Lien Notes Indenture) provides for a 30-day grace period, which expired on July 15, 2020. A failure to pay the interest within the 30-day grace period would constitute an event of default under the Second Lien Notes Indenture and cross defaults under our other debt instruments and agreements. We did not make the July 15, 2020 interest payment and commenced bankruptcy proceedings.

~~2014~~ Revolving Credit Facility

~~As of June 30,~~On October 27, 2020, we ~~had no ability~~entered into a Credit Agreement with Citibank, N.A., as administrative agent, and certain other lenders. This credit agreement currently consists of a $492 million senior revolving loan facility (Revolving Credit Facility), which we are permitted to ~~borrow under~~increase if we obtain additional commitments from new or existing lenders. Our aggregate commitment was $540 million as of March 31, 2021, which was automatically reduced to $492 million in April 2021 pursuant to the terms of our ~~2014~~Revolving Credit Facility. Our Revolving Credit Facility ~~due to~~also includes a sub-limit of $200 million for the ~~Forbearance Agreements described above. As~~issuance of ~~June 30, 2020 and December 31, 2019, we had~~ letters of ~~credit outstanding of $152 million and $165 million, respectively. These~~credit. The letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

The borrowing base is redetermined around April and October of each year and was most recently set at $1.2 billion in May 2021. The borrowing base takes into account the estimated value of our proved reserves, total indebtedness and other relevant factors consistent with customary reserves-based lending criteria. The amount we are able to borrow under our Revolving Credit Facility is limited to the amount of the commitment described above.

As of March 31, 2021 and April 30, 2021, our availability for borrowing under the Revolving Credit facility was as follows:


	Successor
	March 31,		April 30,
	2021		2021
	(in millions)
Borrowing capacity	$	540	$	492
Letters of credit outstanding	(125)		(125)
Total availability	$	415	$	367

On May 7, 2021, we amended the Revolving Credit Facility to:

•increase our borrowing base from $1.167 billion to $1.2 billion;

•evidence the reduction in the aggregate commitment of lenders from $540 million to $492 million;

•increase our capacity to make certain restricted payments;

•reduce the minimum amount of hedges that we are required to maintain for a rolling 24 month period on reasonably anticipated forecasted crude oil production from 50% to 33% so long as our total net leverage ratio is less than 2.00:1.00; and

On January 20, 2021, we completed an offering of $600 million in aggregate principal amount of our 7.125% senior unsecured notes due 2026 (Senior Notes). The net proceeds of $588 million, after $12 million of debt issuance costs, were used to repay in full our Second Lien Term Loan and EHP Notes, with the remainder used to repay substantially all of the then outstanding borrowings under our Revolving Credit Facility. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report for a description of our Second Lien Term Loan and EHP Notes. We recognized a $2 million loss on extinguishment of debt, including unamortized debt issuance costs, associated with these repayments.

Security – Our Senior Notes are general unsecured obligations which are guaranteed on a senior unsecured basis by certain of our material subsidiaries.

Redemption – Prior to February 1, 2023, we may elect to redeem up to 35% of the aggregate principal amount of our Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 107% of the aggregate amount of the Senior Notes redeemed, plus accrued and unpaid interest. In addition, prior to February 1, 2023, we may redeem the Senior Notes at a “make whole” premium plus accrued and unpaid interest. On or after February 1, 2023, we may redeem the Senior Notes at any time prior to the maturity date at a redemption price equal to (i) 104% of the principal amount if redeemed in the twelve months beginning February 1, 2023, (ii) 102% of the principal amount if redeemed in the twelve months beginning February 1, 2024 and (iii) 100% of the principal amount if redeemed after February 1, 2025, in each case plus accrued and unpaid interest.

Other Covenants – Our Senior Notes include covenants that, among other things, restrict our ability to incur additional indebtedness, issue preferred stock, grant liens, make asset sales and investments, repay existing indebtedness, make subsidiary distributions and enter into transactions that would result in fundamental changes.

Events of Default and Change of Control – Our Senior Notes provide for certain triggering events, including upon a change of control, as defined in the indenture, that would require us to repurchase all or any part of the Senior Notes at a price equal to 101% of the aggregate principal amount plus accrued and unpaid interest.

At March 31, 2021, we were in compliance with all financial and other debt covenants under our Revolving Credit Facility and Senior Notes.

Predecessor Note Repurchases

In the ~~six months ended June 30,~~first quarter of 2020, we repurchased $7 million in face value of our Second Lien Notes for $3 million in cash resulting in a pre-tax gain of $5 million, including the effect of unamortized deferred gain and issuance costs. ~~In the six months ended June 30, 2019, we repurchased approximately $76 million~~ See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in ~~face value~~our 2020 Annual Report for a description of our Second Lien ~~Notes for $59 million in cash resulting in a pre-tax gain of $26 million, including the effect of unamortized deferred gain and issuance costs.~~Notes.

~~At June 30, 2020, we~~We estimate that the fair value of our variable rate debt ~~which is classified as Level 1, based on prices from known~~approximates its carrying value because the interest rate approximates current market ~~transactions or quoted market prices for our instruments. At December 31, 2019,~~rates. As shown in the table below, we estimated the fair value of ~~the variable~~our fixed rate ~~portion of our debt was~~Senior Notes based on ~~other~~ observable inputs (Level ~~2) inputs. The estimated~~1) and the fair value of our debt at June 30, 2020 and December 31, 2019, including the fair value of the variable-rate portion, was $1.2 billion and $3.8 billion, respectively, compared to a carrying value of $5.1 billion and $5.0 billion, respectively.EHP Notes with no observable inputs (Level 3).


	Successor
	March 31,		December 31,
	2021		2020
	(in millions)
Variable rate debt	$	0	$	299
Fixed rate debt	0		0

Senior Notes	611		0
EHP Notes	0		300
Fair Value of Long-Term Debt	$	611	$	599

NOTE 6 JOINT VENTURES

~~Noncontrolling Interests~~The following is a summary of our current consolidated joint venture arrangements:

The following table presents the changes in noncontrolling interests for our consolidated JVs, which are reported in equity and mezzanine equity on the condensed consolidated balance sheets for the six months ended June 30, 2020 and 2019:

Equity Attributable to
Noncontrolling Interest
Mezzanine Equity - Redeemable Noncontrolling Interests
Ares JV BSP JV Total Ares JV Elk Hills Carbon JV Total
(in millions)
Balance, December 31, 2019 $ — $ 93 $ 93 $ 802 $ — $ 802
Net income (loss) attributable to noncontrolling interests 3 12 15 61 (1) 60
Contributions from noncontrolling interest holders, net — — — — 2 2
Distributions to noncontrolling interest holders (3) (29) (32) (36) — (36)
Balance, June 30, 2020 $ — $ 76 $ 76 $ 827 $ 1 $ 828
Balance, December 31, 2018 $ 15 $ 99 $ 114 $ 756 $ — $ 756
Net (loss) income attributable to noncontrolling interests (6) 1 (5) 57 — 57
Contributions from noncontrolling interest holders, net — 49 49 — — —
Distributions to noncontrolling interest holders (4) (25) (29) (36) — (36)
Balance, June 30, 2019 $ 5 $ 124 $ 129 $ 777 $ — $ 777

~~Ares~~BSP JV

In February ~~2018, our wholly owned subsidiary California Resources Elk Hills, LLC (CREH)~~2017, we entered into a ~~midstream JV~~development joint venture (JV) with ~~ECR, a portfolio company of Ares. The Ares JV holds the Elk Hills power plant (a 550-megawatt~~Benefit Street Partners (BSP) to develop certain oil and natural gas fired power plant) and a 200 MMcf/d cryogenic gas processing plant. We hold 50% of the Class A common interest and 95.25% of the Class C common interest in the Ares JV. ECR holds 50% of the Class A common interest, 100% of the Class B preferred interest and 4.75% of the Class C common interest. The Ares JV is required to distribute each month its excess cash flow over its working capital requirements first to the Class B holders and then to the Class C common interests, on a pro-rata basis. As contemplated by the terms of the JV, CREH purchases electricity, steam and gas processing services from the Ares JV (subject to certain limitations, including certain geographical limitations) in exchange for monthly capacity payments pursuant to the terms of a Commercial Agreement, the proceeds of which will be used by the Ares JV to make distributions as contemplated by the Second Amended and Restated Limited Liability Company Agreement of Elk Hills Power, LLC. CREH also serves as the operator of the Ares JV and provides operational and support servicesassets in exchange for a ~~monthly fee pursuant~~preferred interest in the BSP JV. BSP is entitled to ~~a Master Services Agreement.~~

We can cause the Ares JV to redeem ECR's Class A and Class B interests, in whole, but not in part, at any time by paying $750 million for the Class B interest and $60 million for the Class A interest, plus any previously accrued but unpaid preferred distributions and, if it receives cash distributions equal to a ~~make-whole payment if~~predetermined threshold, the ~~redemption happens prior~~preferred interest is automatically redeemed in full with no additional payment. BSP has invested $200 million to five years from inception. We have the option to extend the redemption period for up to an additional two and one-half years, in which case the interests can be redeemed for $750 million for the Class B interest and $80 million for the Class A interest, plus any previously accrued but unpaid preferred distributions and a make-whole payment if the redemption happens prior to seven and one-half years from inception.

ECR can sell its Class A and Class B interest or cause a sale of the Ares JV assets in certain circumstances, which include but are not limited to the following: (i) we do not cause the Ares JV to exercise its option to redeem the Class A and Class B interest held by ECR by the end of the seven and one-half year redemption period, (ii) we fail to make payment for purchases of power or gas processing services followed by the failure to make a preferred distribution payment within 60 days, (iii) we default on indebtedness in excess of $100 million and such indebtedness is declared due and payable or (iv) we commence bankruptcy proceedings.

~~See~~ ~~Note 1 Basis of Presentation~~ ~~regarding our Chapter 11 Cases and the Settlement Agreement entered into relating to the Ares JV.~~

Our condensed consolidated statements of operations reflect the operations of the Ares JV, with ECR's share of net income (loss) reported in net income attributable to noncontrolling interests. ECR's redeemable noncontrolling interests are reported in mezzanine equity due to an embedded optional redemption feature.

~~Benefit Street Partners (BSP) JV~~

date, before transaction costs. Our condensed consolidated results reflect the operations of our development JV with BSP, with BSP's preferred interest reported in equity on our condensed consolidated balance sheets and BSP’s share of net income (loss) reported in net income attributable to noncontrolling interests inon our condensed consolidated statements of ~~operations.~~operations for all periods presented. Distributions to our joint venture partner are reported as financing cash outflows on our condensed consolidated statements of cash flows for all periods presented.

Elk Hills Carbon JV

In January 2020, we entered into an agreement with OGCI Climate Investments ~~Elk Hills Carbon Inc.~~LLP (OGCI) to determine the technical and economic feasibility of retrofitting the Elk Hills power plant with a post-combustion, carbon-capture system, which includes a ~~Front-End Engineering Design~~front-end engineering design (FEED) scope and study. The project received financial assistance from the U.S. Department of Energy and project participants include us, Electric Power Research Institute (EPRI), and Fluor Corporation. We formed a joint venture with OGCI called Elk Hills Carbon LLC (Elk Hills Carbon JV) ~~with OGCI~~ to assist with our share of the ~~initial~~ funding obligation. OGCI contributed approximately $2 million to the Elk Hills Carbon JV in the first quarter of 2020 and the cost-sharing payment was made to EPRI during the second quarter of 2020. We are currently evaluating the results of the FEED scope and study. The amounts related to our Elk Hills Carbon JV are not significant to our condensed consolidated financial statements for all periods presented.

The following is a summary of a consolidated joint venture arrangement which was terminated in October 2020 in connection with our emergence from bankruptcy:

Ares JV

In February ~~2020.~~2018, our wholly-owned subsidiary California Resources Elk Hills, LLC entered into a midstream joint venture with ECR Corporate Holdings, L.P. (ECR), a portfolio company of Ares, with respect to the Elk Hills power plant and a cryogenic gas processing plant (Ares JV). These assets were held by the joint venture entity, Elk Hills Power, LLC (Elk Hills Power). We held 50% of the Class A common interest and 95.25% of the Class C common interest in Elk Hills Power and ECR held 50% of the Class A common interest, 100% of the Class B preferred interest and 4.75% of the Class C common interest. As described in Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report, upon our emergence from bankruptcy, we acquired all of the equity interests held by ECR in exchange for EHP Notes, 20.8% (subject to dilution) of our common stock and approximately $2 million in cash.

Our condensed consolidated statements of operations for the three months ended March 31, 2020 reflect the operations of the ~~Elk Hills Carbon~~Ares JV, with ~~OGCI's~~ECR's share of net income (loss) reported in net income attributable to noncontrolling interests. ~~OGCI's redeemable noncontrolling interests~~Distributions to our former joint venture partner are reported ~~in mezzanine equity due to an optional redemption feature.~~as financing cash outflows on our condensed consolidated statement of cash flows for the period ended March 31, 2020.

Other

In July 2019, we entered into a development joint venture with Alpine Energy Capital, LLC (Alpine) to develop portions of our Elk Hills field (Alpine JV). Alpine made an initial commitment to invest $320 million over a period of up to three years in accordance with a 275-well development plan. On March 27, 2020, Alpine elected to suspend its funding obligations pursuant to a contractual right that is triggered if the average NYMEX 12-month forward strip price for Brent crude oil falls below $45 per barrel over a 30-trading day period. The suspension is automatically lifted and Alpine is obligated to renew funding at such time as the average price exceeds that threshold over any 30-trading day period. If prices remain below the threshold for over 100 consecutive trading days, the development phase may be terminated by us, subject to agreement by Alpine.

For more information on our other joint ventures that are unconsolidated joint ventures, including the Alpine JV, the JV with Macquarie Infrastructure and Real Assets Inc. ~~(MIRA JV)~~, and the JV with Royale Energy, Inc. ~~(Royale JV)~~, please see Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our ~~most recent Form 10-K for the year ended December 31, 2019.~~2020 Annual Report.

NOTE 7 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

We, or certain of our subsidiaries, are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020 were not material to our condensed consolidated balance sheets as of such dates.

In October 2020, Signal Hill Services, Inc. defaulted on its decommissioning obligations associated with 2 offshore platforms. The Bureau of Safety and Environmental Enforcement determined that former lessees, including our former parent, Occidental Petroleum Corporation (Oxy) with an approximately 35% share, are responsible for accrued decommissioning obligations associated with these offshore platforms. Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy. We are currently evaluating this claim.

We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves ~~accrued would not~~cannot be ~~material to our condensed consolidated financial statements taken as a whole.~~

Subject to certain exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically stayed, among other things, the continuation of most judicial or administrative proceedings or the filing of other actions against or on behalf of us or our property to recover on, collect or secure a claim arising prior to July 15, 2020 or to exercise control over property of our bankruptcy estates, unless and until the Bankruptcy Court modifies or lifts the automatic stay as to any such action, or judicial or administrative proceeding. Notwithstanding the general application of the automatic stay described above, governmental authorities may determine to continue actions brought under regulatory powers.accurately determined.

NOTE 8 DERIVATIVES

We ~~use~~maintain a ~~variety of derivative instruments in implementing our~~commodity hedging program primarily focused on crude oil to help protect our cash ~~flow, operating margin~~flows, margins and capital program from the ~~cyclical nature~~volatility of commodity prices and interest-rate movements. These derivatives are intended to help us maintain adequate liquidity and improve our ability to comply with the covenants of our credit facilities in case of price deterioration.

prices. We did not have any derivative instruments designated as accounting hedges as of and during the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 and ~~2019.~~2020. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not accounted for as accounting hedges.

~~The Senior DIP~~Our Revolving Credit ~~Agreement~~Facility requires ~~us to enter into hedging arrangements covering at least 25%~~that we hedge a significant amount of ~~our share of expected~~ crude oil production for a period of 36 months from the next twelve months. On July 17, 2020, the Bankruptcy Court authorized us to engage in hedging activities. On July 24, 2020, we entered into various derivative instruments through July 2021 to satisfy this requirement.

~~Commodity-price risk~~ — In March 2020, we monetized all of our crude oil hedges in place for April 2020 forward with our counterparties, except for certain hedges held by our BSP JV, for approximately $63 million. We recognized the proceeds received in net derivative gain (loss) from commodity contracts on our condensed consolidated statements of operations in the first quarter of 2020. We did not enter into any new hedges during the second quarter of 2020.

The BSP JV holds crude oil derivatives and natural gas swaps for insignificant volumes through 2021 that are included in our consolidated results. The hedges entered into by the BSP JV could affect the timingeffective date of the ~~redemption of BSP's preferred interest.~~

facility. In addition, the Revolving Credit Facility requires that we maintain hedges on production for not less than two years from each quarter end.

1713

Summary of open derivative contracts — We held the following Brent-based crude oil contracts as of March 31, 2021:


	Q2 2021		Q3 2021		Q4 2021		2022		January - October 2023
Sold Calls
Barrels per day	33,537		36,362		36,700		30,783		17,758
Weighted-average price per barrel	$	48.73	$	50.31	$	60.70	$	59.37	$	58.01





Purchased Puts
Barrels per day	37,872		36,617		35,483		30,783		17,758
Weighted-average price per barrel	$	40.00	$	40.00	$	40.00	$	40.00	$	40.00

Sold Puts
Barrels per day	15,149		14,647		14,193		3,042		0
Weighted-average price per barrel	$	31.41	$	30.00	$	32.00	$	32.00	$	0

Swaps
Barrels per day	9,639		10,063		10,922		7,069		5,919
Weighted-average price per barrel	$	46.35	$	49.09	$	51.11	$	47.34	$	47.57

The outcomes of the derivative positions are as follows:

•Sold calls – we make settlement payments for prices above the indicated weighted-average price per barrel.

•Purchased puts – we receive settlement payments for prices below the indicated weighted-average price per barrel.

•Sold puts – we make settlement payments for prices below the indicated weighted-average price per barrel.

•Swaps – we make settlement payments for prices above the indicated weighted-average price per barrel and receive settlement payments for prices below the indicated weighted-average price per barrel.

We use combinations of these positions to meet the requirements of our Revolving Credit Facility and to increase the efficacy of our hedging program.

Fair value of derivatives — The following ~~table presents~~tables present the fair values on a recurring basis (at gross and net) of our outstanding commodity derivatives as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019:~~2020:

June 30, 2020
Balance Sheet Classification Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheet Net Fair Value Presented in the Balance Sheet
Assets: (in millions)
  Other current assets, net $ 7 $ — $ 7
  Other assets — — —
Liabilities:
  Accrued liabilities — — —
Total derivatives $ 7 $ — $ 7


March 31, 2021 (Successor)
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	(in millions)
Other current assets	$	12	$	(12)	$	0
Other assets	38		(38)		0

Liabilities
Accrued liabilities	(163)		12		(151)
Other long-term liabilities	(124)		38		(86)
	$	(237)	$	0	$	(237)

December 31, 2019
Balance Sheet Classification Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheet Net Fair Value Presented in the Balance Sheet
Assets: (in millions)
  Other current assets, net $ 49 $ (10) $ 39
  Other assets 1 — 1
Liabilities:
  Accrued liabilities (15) 10 (5)
Total derivatives $ 35 $ — $ 35


December 31, 2020 (Successor)
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	(in millions)
Other current assets, net	$	21	$	(21)	$	0
Other assets	63		(63)		0

Liabilities
Accrued liabilities	(71)		21		(50)
Other long-term liabilities	(69)		63		(6)
	$	(56)	$	0	$	(56)

~~Interest-rate risk~~ —We hold derivative contracts that limit our interest-rate exposure with respect to $1.3 billion of our variable-rate indebtedness. These interest-rate contracts reset monthly and require the counterparties to pay any excess interest owed on such amount in the event the one-month LIBOR exceeds 2.75% for any monthly period prior to May 2021. For the quarters ended June 30, 2020 and 2019, we reported 0 change in fair value on these contracts in other non-operating expenses on our consolidated statements of operations.

~~Fair value of derivatives~~ — Our derivative contracts are measured at fair value using industry-standard models with various inputs, including quoted forward prices, and are classified as Level 2 in the required fair value hierarchy for the periods presented. We ~~recognize~~recognized fair value changes on derivative instruments in each reporting ~~period.~~period in net derivative (loss) gain from commodity contracts on our condensed consolidated statements of operations for the three months ended March 31, 2021 and 2020. The changes in fair value result from the relationship between our existing positions, volatility, time to expiration, contract prices ~~or interest rates~~ and the associated forward curves.

Fair value of interest rate contracts — At March 31, 2021, we held derivative contracts that limited our interest-rate exposure with respect to a notional amount of $1.3 billion of variable-rate indebtedness. The fair value of our interest-rate derivative contracts was not significant for all periods presented and these contracts expired on May 4, 2021.

NOTE 9 EARNINGS PER SHARE

We compute basic and diluted earnings per share (EPS) using the treasury stock method for the three months ended March 31, 2021 and the two-class method for the three months ended March 31, 2020 which is required for participating securities. Certain of our restricted and performance stock unit awards ~~are~~outstanding during the Predecessor period were considered participating securities because they ~~have~~had non-forfeitable dividend rights at the same rate as our pre-emergence common stock. Our restricted and performance stock unit awards granted in the first quarter of 2021, as described in Note 15 Stock-Based Compensation, are not considered participating securities since the dividend rights on unvested shares are forfeitable.

Under the two-class method, undistributed earnings allocated to participating securities are subtracted from net income attributable to common stock in determining net income available to common stockholders. In loss periods, no allocation is made to participating securities because participating securities do not share in losses. For basic EPS, the weighted-average number of common shares outstanding excludes ~~outstanding~~underlying shares related to unvested ~~restricted stock awards.~~equity-settled awards and warrants. For diluted EPS, the basic shares outstanding are adjusted by adding ~~all potentially dilutive securities.~~

potential common shares, if dilutive.

1815

The following table presents the calculation of basic and diluted EPS, for the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 and ~~2019:~~2020:

Three months ended
June 30, Six months ended
June 30,
2020 2019 2020 2019
Basic EPS calculation (in millions, except per-share amounts)
Net (loss) income $ (247) $ 41 $ (1,992) $ (3)
Net income attributable to noncontrolling interests (24) (29) (75) (52)
Net loss (income) attributable to common stock (271) 12 (2,067) (55)
Weighted-average common shares outstanding — basic
49.5 48.9 49.4 48.8
Basic EPS $ (5.47) $ 0.25 $ (41.84) $ (1.13)
Diluted EPS calculation
Net (loss) income $ (247) $ 41 $ (1,992) $ (3)
Net income attributable to noncontrolling interests (24) (29) (75) (52)
Net loss (income) attributable to common stock (271) 12 (2,067) (55)
Weighted-average common shares outstanding — basic
49.5 48.9 49.4 48.8
Dilutive effect of potentially dilutive securities — 0.3 — —
Weighted-average common shares outstanding — diluted
49.5 49.2 49.4 48.8
Diluted EPS $ (5.47) $ 0.24 $ (41.84) $ (1.13)
Weighted-average anti-dilutive shares 5.2 1.9 4.9 2.6


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
(in millions, except per-share amounts)
Numerator for Basic and Diluted Earnings per Share
Net loss	$	(89)	$	(1,745)
Less: net income attributable to noncontrolling interests	(5)		(51)
Net loss attributable to common stock	$	(94)	$	(1,796)

Denominator for Basic and Diluted Earnings per Share
Weighted-average shares	83.3		49.3







Earnings per Share
Basic	$	(1.13)	$	(36.43)
Diluted	$	(1.13)	$	(36.43)

Weighted-average anti-dilutive shares	5.4		4.6

NOTE 10 PENSION AND POSTRETIREMENT BENEFIT PLANS

The following table sets forth the components of the net periodic benefit costs for our defined benefit pension and postretirement benefit plans for the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 and ~~2019:~~2020:

Three months ended June 30,
2020 2019
Pension
Benefit Postretirement
Benefit Pension
Benefit Postretirement
Benefit
(in millions)
Service cost $ 1 $ 1 $ — $ 1
Interest cost — 1 — 2
Expected return on plan assets — — — (1)
Recognized actuarial loss — — — 1
Settlement loss — — 1 —
Total $ 1 $ 2 $ 1 $ 3

Six months ended June 30,
2020 2019
Pension
Benefit Postretirement
Benefit Pension
Benefit Postretirement
Benefit
(in millions)
Service cost $ 1 $ 2 $ — $ 2
Interest cost 1 2 1 3
Expected return on plan assets — — (1) (1)
Recognized actuarial loss — — 1 1
Settlement loss — — 1 —
Total $ 2 $ 4 $ 2 $ 5


	Successor				Predecessor
	Three months ended March 31,				Three months ended March 31,
	2021				2020
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
(in millions)
Service cost	$	0	$	1	$	0	$	1
Interest cost	0		1		1		1



Total	$	0	$	2	$	1	$	2

We did 0t make ~~any~~significant contributions to our defined benefit plans for the three months ended March 31, 2021. We expect to satisfy minimum funding requirements with contributions of approximately $3 million to our defined benefit pension plans during the remainder of 2021.

We did 0t make significant contributions to our defined benefit pension plans for the three ~~and six~~ months ended ~~June 30,~~March 31, 2020. The Coronavirus Aid, Relief, and Economic Security Act (CARES Act) ~~became law~~was enacted on March 27, 2020 and ~~allows~~allowed for the deferral of contributions to a single employer pension plan otherwise due during 2020 to January 1, 2021. We deferred contributions to our defined benefit pension plans of approximately $5 million ~~for the first six months of~~during 2020, ~~until~~which we paid in December 2020. We made contributions of $1 million for the three months and six months ended June 30, 2019. The 2019 settlement losses, which were reclassified from accumulated other comprehensive income, were associated with early retirements.

NOTE 11 REVENUE RECOGNITION

We derive ~~substantially all~~most of our revenue from sales of oil, natural gas and NGLs, with the remaining revenue primarily generated from sales of electricity and marketing activities related to storage and managing excess pipeline capacity.

The following table provides disaggregated revenue for ~~the three~~sales for oil, natural gas and ~~six months ended June 30, 2020 and 2019:~~NGLs to customers:

Three months ended
June 30, Six months ended
June 30,
2020 2019 2020 2019
(in millions)
Oil and natural gas sales:
Oil $ 193 $ 496 $ 549 $ 976
Natural gas 26 43 64 105
NGLs 26 39 62 98
245 578 675 1,179
Other revenue:
Electricity 19 16 32 50
Marketing, trading and other 16 38 67 182
35 54 99 232
Net derivative gain (loss) from commodity contracts (4) 21 75 (68)
Total revenues $ 276 $ 653 $ 849 $ 1,343


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
(in millions)
Oil, natural gas and NGL sales:
Oil	$	331	$	356
Natural gas	47		38
NGLs	54		36
	$	432	$	430

NOTE 12 LEASES

Balance sheet information related to our operating and finance leases ~~as of June 30, 2020 and December 31, 2019~~ was as follows:

Balance Sheet Location June 30, 2020 December 31, 2019
(in millions) (in millions)
Right-of-Use Assets
Operating lease, net Other assets $ 45 $ 59
Finance lease, net PP&E 1 2
Total right-of-use assets $ 46 $ 61
Lease Liabilities
Current
   Operating lease Accrued liabilities $ 14 $ 27
   Finance lease Accrued liabilities 1 1
Long-term
   Operating lease Other long-term liabilities 33 37
   Finance lease Other long-term liabilities — 1
Total lease liabilities $ 48 $ 66


		Successor
	Classification	March 31, 2021		December 31, 2020
		(in millions)
Assets
Operating	Other assets	$	39	$	38
Finance	PP&E	1		1
Total leased assets		$	40	$	39

Liabilities
Current
Operating	Accrued liabilities	$	9	$	6
Finance	Accrued liabilities	1		1
Long-term
Operating	Other long-term liabilities	34		35
Finance	Other long-term liabilities	0		0
Total lease liabilities		$	44	$	42

Our operating lease assets and liabilities ~~decreased~~increased from year end ~~2019~~2020 primarily due to ~~releasing 5 of our leased~~adding 1 drilling ~~rigs~~rig in the first quarter of ~~2020 in response to the economic environment. Our remaining 2 leased drilling rigs have been cold stacked and were included with our proved properties in our impairment assessment as discussed in~~ ~~Note 14 Asset Impairments. These right-of-use assets were not impaired.~~2021.

NOTE 13 INCOME TAXES

We estimate our annual effective income tax rate to record our quarterly income tax provision in the jurisdictions in which we operate. Statutory tax rate changes and other significant or unusual items, if any, are not included in our annual effective income tax rate and are instead recognized as discrete items in the quarter in which they occur. ~~We maintained a full valuation allowance against our net deferred tax assets after considering cumulative losses, including oil and natural gas asset impairments.~~

For the ~~six~~three months ended ~~June 30,~~March 31, 2021 and 2020, ~~and 2019,~~ we did not provide any current or deferred income tax provision or benefit. The difference between our statutory tax rate and our effective tax rate of 0 for ~~the~~all periods presented includes changes to maintain our full valuation allowance against our net deferred tax assets given our recent and anticipated future earnings trends. We believe that there is a reasonable possibility that some or all of this allowance could be released in the foreseeable future. However, the amount of the net deferred tax assets considered realizable depends on the sustained level of profitability that we can achieve.

The CARES Act increased the limitation on the deductibility of business interest expense from 30% to 50% of adjusted taxable income in 2019 and 2020 along with other provisions intended to provide relief to corporate taxpayers. There was no impact on our income tax provision due to our full valuation allowance.

On July 28, 2020 the Internal Revenue Service (IRS) issued final and new proposed regulations related to the limitation on the deduction for business interest. We are in the process of evaluating the final and new proposed regulations, which may change the composition of our deferred tax assets, specifically the amount reported for net operating loss and business interest expense carryforwards. Due to our full valuation allowance position, these regulations are not expected to have a material impact to our financial statements.

NOTE 14 ASSET IMPAIRMENTS

~~We did 0t impair any~~The following table presents a summary of our ~~long-lived assets during~~asset impairments:


	Successor		Predecessor
	March 31, 2021		March 31, 2020
(in millions)
Proved oil and natural gas properties	$	0	$	1,487
Unproved properties	0		228
Other	3		21
Total	$	3	$	1,736

At March 31, 2021, we recorded a $3 million impairment which was triggered by the ~~three-month period ended June 30,~~change in our business strategy and capital allocation priorities resulting in the impairment of capitalized costs related to projects which were abandoned.

At March 31, 2020, ~~but~~we recorded a $1.7 billion impairment ~~during the three-month period ended March 31, 2020. Our impairments of long-lived assets were~~which was triggered by the sharp drop in commodity prices at the end of the first quarter of 2020 due to ~~decreased~~the significant decrease in demand for oil and natural gas products as a result of the Coronavirus Disease 2019 (COVID-19) pandemic coupled with the over-supply resulting from a price war between members of the Organization of the Petroleum Exporting Countries (OPEC) ~~and~~, Russia and other allied producing countries. ~~The following table presents a summary of our~~Other asset ~~impairments:~~


	~~Six months ended~~
	~~June 30, 2020~~
	~~(in millions)~~
~~Proved oil and natural gas properties~~	$	~~1,487~~
~~Unproved properties~~	~~228~~
~~Unrecovered capital costs~~	11
~~Inventory~~	7
~~Other~~	3
~~Total~~	$	~~1,736~~

~~Proved oil and natural gas properties~~ — The fair values of our proved oil and natural gas properties were determined as of the date of the assessment using discounted cash flow models incorporating a number of fair value inputs which are categorized as Level 3 on the fair value hierarchy. These inputs were based on management's expectations for the future considering the current environment and included index prices based on forward curves until the market became illiquid and internally generated price forecasts thereafter, pricing adjustments for differentials, estimates of future oil and natural gas production, estimated future operating costs and capital development plans based on the embedded price assumptions. We used a market-based weighted average cost of capital to discount the future net cash flows. The impairment charge primarily related to a steamflood property locatedimpairments recorded in the ~~San Joaquin basin.~~

~~Unproved properties~~ ~~— We determined our ability to develop our unproved properties was constrained for~~three months ended March 31, 2020 primarily included the ~~foreseeable future. Accordingly, we do not intend to develop these assets and impaired all~~write-off of ~~our unproved properties in the first quarter of 2020, which primarily consist of leases held by production in the San Joaquin basin.~~

~~Unrecovered capital costs~~ ~~— Net~~ amounts due from joint interest partners which ~~are included in other current assets on our condensed consolidated balance sheet, include amounts for capital and operating costs incurred by us that are~~were recoverable solely from our ~~partners'~~partners’ share of future production from associated fields. The dramatic commodity price decline during the first quarter of 2020 resulted in changes to our cash flow forecasts and we impaired the carrying value of these ~~assets.~~amounts. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 13 Asset Impairment in our 2020 Annual Report for a description of our impairment of proved and unproved oil and gas properties as of March 31, 2020.

NOTE 15 STOCK-BASED COMPENSATION ~~PLANS~~

~~Changes to the 2020 Compensation Programs~~

In connection with the unprecedented circumstances affecting the industry and market volatility resulting from the recent industry downturn, we reviewed our incentive programs for the entire workforce to determine whether those programs appropriately align compensation opportunities with our 2020 goals and ensure the stabilityAs a result of our ~~workforce. Following this review, effective May 19, 2020,~~bankruptcy, our ~~Board of Directors approved changes in the variable compensation programs for~~Amended and Restated California Resources Corporation Long-Term Incentive Plan was cancelled and, upon emergence, all participating employees. The previously established target amounts of 2020 variable compensation programs did not change; however, all amounts that vest will be settled in cash and the replacement awards are no longer stock-based compensation. As a condition to receiving any award, participants waived participation in our 2020 annual incentive program and forfeited all stock-based compensation awards previously granted in 2020. There were no changes tooutstanding stock-based compensation awards granted prior to February 2020. Changes to the variable compensation programs will have the effect of accelerating the associated payments into 2020 from future periods. However, the total amount of compensation to be paid under ~~the variable compensation programs at target for 2020 remains largely the same as the amounts that would have been paid at target prior to the changes.~~this plan were cancelled.

~~Employee Stock Purchase Plan~~

On ~~May 26, 2020,~~January 18, 2021, our Board of Directors approved the ~~termination of the~~ California Resources Corporation ~~2014 Employee Stock Purchase Plan. No~~2021 Long Term Incentive Plan (2021 Incentive Plan) and as a result, the 2021 Incentive Plan became effective. The 2021 Incentive Plan provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, vested stock awards, dividend equivalents, other stock-based awards and substitute awards to employees, officers, non-employee directors and other service providers of the Company and its affiliates. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 14 Stock-Based Compensation in our 2020 Annual Report for additional information including the number of shares ~~were issued under~~authorized for awards.

Shares of our common stock may be withheld by us in satisfaction of tax withholding obligations arising upon the ~~plan after~~vesting of restricted stock and performance stock units.

Stock-based compensation expense is recorded as a component of operating costs and general and administrative expenses on our condensed consolidated statements of operations as follows:


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
(in millions)
General and administrative expenses	$	2	$	1
Operating costs	0		(1)
Total stock-based compensation expense	$	2	$	0

For the three months ended March 31, ~~2020.~~2021 and 2020, we did 0t recognize any income tax benefit related to our stock-based compensation. For the three months ended March 31, 2020, we made cash payments of $8 million for the cash-settled portion of our pre-emergence awards.

Restricted Stock Units

In the first quarter of 2021, we granted restricted stock units (RSUs) to our non-employee directors and certain of our executives. The awards generally vest ratably over three years, with one third of the granted units vesting on each of the first three anniversaries of the applicable date of grant. RSUs are settled in shares of our common stock at the end of the three-year vesting period.

Compensation expense was measured on the date of grant using the quoted market price of our common stock and is recognized on a straight-line basis over the requisite service periods adjusted for actual forfeitures, if any.

As of March 31, 2021, the unrecognized compensation expense for all of our unvested RSUs was approximately $25 million and is expected to be recognized over a weighted-average period of three years.



	Number of Units	Weighted-Average Grant-Date Fair Value
	(in thousands)

Granted	1,057	$	24.45
Cancelled or Forfeited	(9)	$	24.50
Unvested at March 31, 2021 (Successor)	1,048

Performance Stock Units

In the first quarter of 2021, we granted certain of our executives performance stock units (PSUs). PSUs are earned upon the attainment of specified 60-trading day volume weighted average prices for shares of our common stock during a three-year service period commencing on the grant date. Once units are earned, the earned units are not reduced for subsequent decreases in stock price. For the duration of the three-year period, a minimum of 0% and a maximum of 100% of the PSUs granted could be earned. Earned PSUs vest on the third anniversary of the grant date and are settled in shares of our common stock at that time.



	Number of Units	Weighted-Average Grant-Date Fair Value
	(in thousands)

Granted	869	$	19.47
Cancelled or Forfeited	(9)	$	19.31
Unvested at March 31, 2021 (Successor)	860

The grant date fair value and associated equity compensation expense was measured using a Monte Carlo simulation model which runs a probabilistic assessment of the number of units that will be earned based on a projection of our stock price during the three-year service period.

The range of assumptions used in the Monte Carlo simulation model for the PSUs granted during the first quarter of 2021 were as follows:





Expected volatility(a)	65.00	%
Risk-free interest rate(b)	0.17% - 0.32%
Dividend yield	0	%
Forecast period (in years)	3

(a)Expected volatility was calculated using a peer group due to our limited trading history since our emergence from bankruptcy.

(b)Based on the U.S. Treasury yield for a three-year term at the grant date.

Compensation expense is recognized on a straight-line basis over the requisite service periods adjusted for actual forfeitures, if any.

As of March 31, 2021, the unrecognized compensation expense for all of our unvested PSUs was approximately $16 million and is expected to be recognized over a weighted-average period of three years.

NOTE 16 ~~CONDENSED CONSOLIDATING FINANCIAL INFORMATION~~SUBSEQUENT EVENTS

~~Our Credit Facilities, Second Lien Notes and Senior Notes are guaranteed both fully and unconditionally and jointly and severally by~~In May 2021, our ~~material wholly owned subsidiaries (Guarantor Subsidiaries). Certain~~Board of Directors authorized a Share Repurchase Program (SRP) to acquire up to $150 million of our ~~subsidiaries do~~common stock through March 31, 2022. The repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions. The SRP does not ~~guarantee~~obligate us to repurchase any dollar amount or number of shares and our ~~Credit Facilities, Second Lien Notes and Senior Notes (Non-Guarantor Subsidiaries) either because they hold assets that are less than 1%~~Board of ~~our total consolidated assets~~Directors may modify, suspend, or ~~because they are not considered a "subsidiary" under~~discontinue authorization of the applicable financing agreement. The following condensed consolidating balance sheets as of June 30, 2020 and December 31, 2019 and the condensed consolidating statements of operations and statements of cash flows for the three and six months ended June 30, 2020 and 2019, as applicable, reflect the condensed consolidating financial information of our parent company, CRC (Parent), our combined Guarantor Subsidiaries, our combined Non-Guarantor Subsidiaries and the elimination entries necessary to arriveprogram at ~~the information for the Company on a consolidated basis.~~any time.

~~The financial information may not necessarily be indicative~~Refer to Note 5 Debt for a description of ~~results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities.~~

lender commitments in April 2021 and a May 2021 amendment to our Revolving Credit Facility which provides flexibility on hedging requirements and increased our capacity to make certain restricted payments.

Condensed Consolidating Balance Sheets
As of June 30, 2020 and December 31, 2019
(in millions)
June 30, 2020
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated
Total current assets $ 22 $ 341 $ 68 $ (28) $ 403
Investments in consolidated subsidiaries 3,156 (53) — (3,103) —
Total property, plant and equipment, net 24 3,972 453 — 4,449
Other assets 1 64 13 — 78
TOTAL ASSETS $ 3,203 $ 4,324 $ 534 $ (3,131) $ 4,930
Total current liabilities 5,409 371 7 (28) 5,759
Other long-term liabilities 159 557 3 — 719
Amounts due to (from) affiliates 87 (88) 1 — —
Mezzanine equity — — 828 — 828
Total equity (2,452) 3,484 (305) (3,103) (2,376)
TOTAL LIABILITIES AND EQUITY $ 3,203 $ 4,324 $ 534 $ (3,131) $ 4,930

December 31, 2019
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated
Total current assets $ 8 $ 436 $ 60 $ (13) $ 491
Investments in consolidated subsidiaries 5,956 223 — (6,179) —
Total property, plant and equipment, net 35 5,846 471 — 6,352
Other assets 1 82 32 — 115
TOTAL ASSETS $ 6,000 $ 6,587 $ 563 $ (6,192) $ 6,958
Total current liabilities 248 469 5 (13) 709
Long-term debt 4,877 — — — 4,877
Deferred gain and issuance costs, net 146 — — — 146
Other long-term liabilities 167 549 4 — 720
Amounts due to (from) affiliates 951 (953) 2 — —
Mezzanine equity — — 802 — 802
Total equity (389) 6,522 (250) (6,179) (296)
TOTAL LIABILITIES AND EQUITY $ 6,000 $ 6,587 $ 563 $ (6,192) $ 6,958

Condensed Consolidating Statements of Operations
For the three and six months ended June 30, 2020 and 2019
(in millions)
Three months ended June 30, 2020
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated
Total revenues $ — $ 253 $ 94 $ (71) $ 276
Total costs 55 357 50 (71) 391
Non-operating (loss) income (135) 3 — — (132)
NET (LOSS) INCOME (190) (101) 44 — (247)
Net income attributable to noncontrolling interests — — (24) — (24)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK $ (190) $ (101) $ 20 $ — $ (271)

Three months ended June 30, 2019
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated
Total revenues $ — $ 610 $ 113 $ (70) $ 653
Total costs 52 490 59 (70) 531
Non-operating (loss) income (83) 2 — — (81)
NET (LOSS) INCOME (135) 122 54 — 41
Net income attributable to noncontrolling interest — — (29) — (29)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK $ (135) $ 122 $ 25 $ — $ 12

Six months ended June 30, 2020
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated
Total revenues $ — $ 779 $ 210 $ (140) $ 849
Total costs 102 2,546 105 (140) 2,613
Non-operating (loss) income (230) 2 — — (228)
NET (LOSS) INCOME (332) (1,765) 105 — (1,992)
Net income attributable to noncontrolling interest — — (75) — (75)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK $ (332) $ (1,765) $ 30 $ — $ (2,067)

Six months ended June 30, 2019
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated
Total revenues $ — $ 1,255 $ 235 $ (147) $ 1,343
Total costs 106 1,074 131 (147) 1,164
Non-operating (loss) income (187) 5 — — (182)
NET (LOSS) INCOME (293) 186 104 — (3)
Net income attributable to noncontrolling interest — — (52) — (52)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK $ (293) $ 186 $ 52 $ — $ (55)

Condensed Consolidating Statements of Cash Flows
For the six months ended June 30, 2020 and 2019
(in millions)
Six months ended June 30, 2020
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated
Net cash (used in) provided by operating activities $ (338) $ 277 $ 154 $ — $ 93
Net cash provided by (used in) investing activities 1 (28) — — (27)
Net cash provided by (used in) financing activities 340 (153) (144) — 43
Increase in cash 3 96 10 — 109
Cash—beginning of period — 6 11 — 17
Cash—end of period $ 3 $ 102 $ 21 $ — $ 126

Six months ended June 30, 2019
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated
Net cash (used in) provided by operating activities $ (348) $ 303 $ 317 $ — $ 272
Net cash used in investing activities (5) (154) (11) — (170)
Net cash provided by (used in) financing activities 353 (149) (296) — (92)
Increase in cash — — 10 — 10
Cash—beginning of period — 7 10 — 17
Cash—end of period $ — $ 7 $ 20 $ — $ 27

2520

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

General

We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We provide ample, affordable and reliable energy in a safe and responsible manner, to support and enhance the quality of life of Californians and the local communities in which we operate. We do this through the development of our broad portfolio of assets while adhering to our commitment to making value-based capital investments. Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘~~company,~~Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.

We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We are incorporated in Delaware and became a publicly traded company on December 1, 2014. Chapter 11 Proceedings

On July 15, 2020, we filed voluntary petitions ~~in the United States Bankruptcy Court~~ for ~~the Southern District of Texas seeking~~ relief under Chapter 11 of Title 11 of the ~~United States~~ Bankruptcy Code ~~as further described below.~~(Chapter 11 Cases). On October 13, 2020, the Bankruptcy Court confirmed our joint plan of reorganization (the Plan) and we subsequently emerged from Chapter 11 on October 27, 2020 with a new Board of Directors, new equity owners and a significantly improved financial position.

Fresh Start Accounting

~~Our condensed consolidated~~See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 3 Fresh Start Accounting in our Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Annual Report) for additional information on the terms of the Plan, our emergence from bankruptcy and application of fresh start accounting.

Organization Changes

In January 2021, we reduced the size of our management team and then realigned several functions in February 2021, which resulted in additional headcount and cost reductions, making progress towards our lower cost operating model. We changed our 2021 capital guidance to reallocate investments to downhole maintenance activities, which will result in an increase in estimated 2021 operating costs. As a result, we expect our sustainable cost savings in general and administrative expense and operating costs to be $80 million in 2021 as compared to 2020 levels. We believe the steps taken to date have improved our financial ~~statements, including~~condition and streamlined our business.

In connection with our emergence from bankruptcy, our Board of Directors was reconstituted in October 2020. On December 31, 2020, our former President, Chief Executive Officer and director Todd A. Stevens departed and Mark A. (Mac) McFarland was appointed as interim Chief Executive Officer in addition to his role as Chair of our Board of Directors. On March 22, 2021, the Board of Directors appointed Mr. McFarland as President and Chief Executive Officer on a permanent basis. On April 15, 2021, Tiffany (TJ) Thom Cepak replaced Mr. McFarland as the Chair of our Board of Directors. Mr. McFarland will continue to serve as a director.

Recent Debt Transactions

In January 2021, we completed a private offering of $600 million in aggregate principal amount of our 7.125% senior unsecured notes due 2026 (Senior Notes). The net proceeds of $588 million, after $12 million of debt issuance costs, were used to repay in full our Second Lien Term Loan and our EHP Notes, ~~thereto, included in~~with the remaining proceeds used to pay down a portion of the outstanding borrowings under our Revolving Credit Facility. For more information on the terms of Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 5 Debt.

In May 2021, we amended the Revolving Credit Facility to:

• ~~have been prepared assuming~~increase our borrowing base from $1.167 billion to $1.2 billion;

•evidence the reduction in the aggregate commitment of lenders from $540 million to $492 million;

•increase our capacity to make certain restricted payments;

•reduce the minimum amount of hedges that we ~~will continue~~are required to maintain for a rolling 24 month period on reasonably anticipated forecasted crude oil production from 50% to 33% so long as our total net leverage ratio is less than 2.00:1.00; and

•increase our maximum hedging limitation to 85% (and permit purchased puts and floors up to 100%) of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids for a ~~going concern. These financial statements do not include any adjustments that might result from the outcome~~48-month period.

Share Repurchase Program

In May 2021, our Board of Directors authorized a Share Repurchase Program (SRP) to acquire up to $150 million of our ~~going concern uncertainty~~common stock through March 31, 2022. The repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or ~~the Chapter 11 Cases (as defined below). There is substantial doubt that we can continue as a going concern if we are~~otherwise in compliance with Rule 10b-18, subject to market conditions. The SRP does not ~~able~~obligate us to ~~complete the plan~~repurchase any dollar amount or number of ~~reorganization contemplated by the RSA~~shares and our Board of Directors may modify, suspend, or ~~another plan of reorganization as part~~discontinue authorization of the Chapter 11 Cases as discussed below. Further, the Chapter 11 Cases could result in a change in the basis of our accounting, which may have a material effect on the carrying value of certain assets and liabilities.program at any time.

Business Environment and Industry Outlook

Commodity Prices

Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related ~~variables~~, ~~especially given current global geopolitical and economic conditions.~~variables. These and other factors make it impossible to predict realized prices reliably. We respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term.

~~Prices~~Global oil prices gradually increased beginning in October 2020 through the first quarter of 2021. Benchmark prices for Brent crude oil ~~and gas products~~ in the first ~~half~~quarter of 2021 increased approximately 35% from the fourth quarter of 2020 ~~have been strongly~~demonstrating a strong recovery from the prior year when oil prices were negatively influenced by the Coronavirus Disease 2019 (COVID-19) ~~pandemic~~pandemic. Current pricing has benefited from the gradual re-opening of the economy and by the ~~actions~~lifting of ~~foreign producers. The COVID-19 pandemic caused an unprecedented demand collapse due~~restrictions related to the ~~shelter-in-place orders, travel restrictions and general economic uncertainty, which negatively impacted crude oil prices. In addition~~,COVID-19 pandemic. Further, members of ~~the~~ Organization of ~~the~~ Petroleum Exporting Countries (OPEC) and ~~Russia did not extend existing~~non-OPEC producers have restrained crude oil production ~~cuts expiring on April 1,~~attempting to reduce oil supplies built during the worst period of the pandemic.

The following table presents the average daily Brent, WTI and NYMEX prices for the three months ended March 31, 2021, December 31, 2020 and ~~Saudi Arabia and Russia announced significant increases in crude oil production. The unprecedented dual impact of~~March 31, 2020:



	Three months ended March 31,		Three months ended December 31,		Three months ended March 31,
	2021		2020		2020
Brent oil ($/Bbl)	$	61.10	$	45.24	$	50.96
WTI oil ($/Bbl)	$	57.84	$	42.66	$	46.17
NYMEX gas ($/MMBtu)	$	2.72	$	2.66	$	2.05

Note: Bbl refers to a ~~severe global oil demand decline due~~barrel; MMBtu refers to ~~the COVID-19 pandemic repercussions coupled with a substantial increase in supply from Saudi Arabia and Russia resulted in a collapse in crude oil prices.~~one million British Thermal Units.

Reduced demand caused shortages in available storage facilities globally and required many oil and gas producers to shut in wells or curtail production. In April 2020, oil prices continued to decline precipitously temporarily reaching negative values for spot WTI crude. In May 2020 and June 2020, oil prices began to recover as producers across the world, including OPEC, Russia, the United States and others started cutting their production levels sharply and announced significant capital reductions, and an easing of shelter-in-place restrictions created partial demand recovery. However, demand and pricing may again decline due to the resurgence of the outbreak across parts of the United States and related re-imposition of certain restrictions. The current futures forward curve for Brent crude indicates that prices may continue at close to current levels but lower than pre-pandemic levels for an extended period of time.

We continue to closely monitor the impact of COVID-19, which negatively impacted our business and results of operations beginning in the first quarter of 2020. The lower commodity prices have continued into the second quarter and are currently expected to remain depressed for an extended period of time based on current futures curves. The extent to which our total year operating results will be impacted by the pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including new information that may emerge concerning potential vaccines, the severity of the pandemic and actions taken to contain it or actions taken by government authorities or other producers in response to commodity price movements, among other things. See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Production and Prices and Part II, Item 1A – Risk Factors~~, below~~ in our 2020 Annual Report for further discussion regarding the impact of the pandemic and declines in commodity prices.

2622

~~The following table presents the average daily Brent, WTI and NYMEX prices for the three and six months ended June 30, 2020 and 2019:~~

Three months ended
June 30, Six months ended
June 30,
2020 2019 2020 2019
Brent oil ($/Bbl) $ 33.27 $ 68.32 $ 42.12 $ 66.11
WTI oil ($/Bbl) $ 27.85 $ 59.82 $ 37.01 $ 57.36
NYMEX gas ($/MMBtu) $ 1.77 $ 2.66 $ 1.91 $ 2.95

~~Note: Bbl refers to a barrel; MMBtu refers to one million British Thermal Units.~~

~~Voluntary Petitions for Relief Under Chapter 11 of the Bankruptcy Code~~

In light of our significant indebtedness and the unprecedented impact to our financial position resulting from the commodity price environment and the COVID-19 pandemic, combined with continued challenging conditions in the credit and capital markets, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code (Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court) on July 15, 2020. The Chapter 11 cases filed by us (Chapter 11 Cases) are being jointly administered under the caption ~~In re California Resources Corporation, et al., Case No. 20-33568 (DRJ). On July 24, 2020, we filed a Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code with the Bankruptcy Court.~~

The commencement of the Chapter 11 Cases constitutes an event of default that accelerated our obligations under the following agreements: (i) Credit Agreement, dated as of September 24, 2014, among JPMorgan Chase Bank, N.A., as administrative agent, and the lenders that are party thereto (2014 Revolving Credit Facility), (ii) Credit Agreement, dated as of August 12, 2016, among The Bank of New York Mellon Trust Company, N.A., as collateral and administrative agent, and the lenders that are party thereto (2016 Credit Agreement), (iii) Credit Agreement, dated as of November 17, 2017, among The Bank of America Mellon Trust Company, N.A., as administrative agent, and the lenders that are party thereto (2017 Credit Agreement), and (iv) the indentures governing our 8% Senior Secured Second Lien Notes due 2022 (Second Lien Notes), 5.5% Senior Notes due 2021 (2021 Notes) and 6% Senior Notes due 2024 (2024 Notes). Additionally, other events of default, including cross-defaults, are present under these debt agreements. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against us, including exercising remedies as a result of any event of default. See ~~Part I, Item 1 – Financial StatementsNote 5 Debt~~ ~~for additional details about our debt.~~

~~Restructuring Support Agreement~~

~~On July 15, 2020, we entered into a Restructuring Support Agreement which was subsequently amended on July 24, 2020 (RSA).~~This RSA contemplates a restructuring plan that establishes a reorganized company with a new capital structure. The transactions contemplated by the RSA plan include (i) entering into a senior secured superpriority DIP credit facility (Senior DIP Facility) in an aggregate principal amount of up to approximately $483 million, (ii) entering into a junior secured superpriority DIP term loan facility in an aggregate amount of $650 million (Junior DIP Facility), (iii) the implementation of financing upon emergence from bankruptcy, (iv) the issuance of new common stock, and (v) a $450 million equity rights offering, backstopped by certain parties to the RSA.

~~Debtor-in-Possession Credit Agreements~~

On July 23, 2020, we entered into (1) a Senior Secured Superpriority DIP Credit Agreement with JPMorgan, as administrative agent, and certain other lenders (Senior DIP Credit Agreement) and (2) a Junior Secured Superpriority DIP Credit Agreement with Alter Domus, as administrative agent, and certain lenders (Junior DIP Credit Agreement). For more information on our debtor-in-possession credit agreements, see ~~Part I, Item 1~~ – ~~Financial Statements, Note 5 Debt~~ ~~and~~ ~~Liquidity and Capital Resources~~ ~~below.~~

~~Ares JV Settlement Agreement~~

~~Going Concern Analysis and~~ Recent Developments

Our spin–off from Occidental Petroleum Corporation (Occidental) on November 30, 2014 burdened us with significant debt which was used to pay a $6.0 billion cash dividend to Occidental. Together with the activity level and payables that we assumed from Occidental and due to Occidental's retentionCertain actions of the ~~vast majority~~new U.S. administration could impact the oil and gas industry. Such actions may include, among other things, the increased regulation of greenhouse gas emissions associated with oil and gas operations, the imposition of a new carbon tax on greenhouse gas emissions and replacing tax incentives related to fossil fuel with incentives for clean energy production. Such outcomes could materially and adversely affect our ~~receivables, our debt peaked at approximately $6.8 billion in May 2015. Since then, we have engaged in a series~~business, results of ~~assets sales, joint ventures, debt exchanges, tenders~~operations and repurchases and other financing transactions to reduce our overall debt and improve our balance sheet. As of June 30, 2020, we had reduced our outstanding debt to approximately $5.1 billion, a substantial portion of which would have matured in 2021.financial condition.

~~We currently expect~~On April 23, 2021, Governor Gavin Newsom signed an executive order directing the California Department of Conservation’s Geologic Energy Management Division to initiate a rulemaking to end the issuance of new permits for well stimulation treatments by January 1, 2024 and instructed the California Air Resources Board to evaluate methods of phasing out oil extraction across the state by 2045. This marks a reversal from the governor’s previous statements that ~~our cash flows, cash on hand~~he lacked the executive authority to ban hydraulic fracturing, and ~~financing available through our DIP credit agreements should provide sufficient liquidity during~~any decision to prohibit the ~~pendency~~extraction of ~~the Chapter 11 Cases. However, for the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are~~oil would likely be subject to significant opposition and legal challenge. Regardless of whether or not such a ~~high degree of risks and uncertainty associated with the Chapter 11 proceedings. The outcome of the Chapter 11 Cases~~ban is ~~also subject~~upheld, we expect little to ~~a high degree of uncertainty and is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court, our creditors, and Ares. There can be~~ no assurance that we will confirm and consummate the plan under the RSA or complete another plan of reorganization with respect to the Chapter 11 proceedings. There is substantial doubt that we can continue as a going concern ifimpact on future development activities because we are not ~~able to complete the plan~~dependent on well stimulation treatments. Less than 1% of ~~reorganization contemplated by the RSA or another plan of reorganization as part of the Chapter 11 Cases.~~

~~For the duration of the Chapter 11 Cases,~~ our ~~operations~~proved reserves require well stimulation and ~~ability to develop and execute~~ our ~~business plan are subject to the risks and uncertainties associated with the Chapter 11 Cases. See~~ ~~Part II, Item 1A~~ – ~~Risk Factors, below for further discussion of these risks and risks related to our ability to continue as a going concern.~~

~~Operations~~current long-term development plans do not include well stimulation.

~~Response to COVID-19 Pandemic and Industry Downturn~~

Operations

We have ~~taken several steps~~the largest privately held oil and ~~continue to actively work to mitigate the effects~~natural gas mineral acreage position in California, consisting of ~~the COVID-19 pandemic~~2.1 million net mineral acres spanning four of California's major oil and ~~the industry downturn on our operations, financial condition and liquidity.~~

In response to the rapid fall in commodity prices, we reduced our 2020 capital budget to a level that maintains the mechanical integrity of our facilities to operate them in a safe and environmentally responsible manner and ceased all field development and growth projects. As a result, our internally funded capital was $3 million in the second quarter of 2020. We also monetized all of our crude oil hedges for April 2020 forward with our counterparties, except for certain hedges held by our joint venture with Benefit Street Partners (BSP JV), for approximately $63 million to enhance our liquidity. We shut in certain wells to reduce operating costs which curtailed average gross production volumes by approximately 6 MBoe/d and average net production volumes by 5 MBoe/d during the second quarter of 2020. As part of our operational efficiency measures, we evaluated our diverse portfolio and our various production mechanisms with a focus on wells with higher operating costs. Our teams utilized our extensive automation controls, monitored weekly well margins, and made temporary adjustments to our producing wells to ensure our operations aligned with the price environment. As a result of these actions, as well as further cost rationalization and streamlining efforts coupled with lower activity levels, our current operating expense run rate is below $45 million per month compared to the first quarter average of $64 million per month. At our current level of capital investment, we anticipate production will continue to decline at a moderate pace through the remainder of the year.

We have also implemented various measures to protect the health of our workforce and to support the prevention of COVID-19 at our plants, rigs, fields and administrative offices. These initiatives were in accordance with the orders and guidance of federal, state and local authorities to mitigate the risks of the disease, and included temporarily closing all our administrative offices and implementing remote working for most office employees. As a result, our management team and substantially all of our office personnel, including finance and accounting teams, worked remotely beginning in March 2020. In June 2020, we began a phased return to the office, focused on those employees for whom remote work was not feasible. In addition, on April 6, 2020, we implemented reduced work hours for nearly all of our office employees and reduced salaries for our management team, in each case on a temporary basis that ended in May 2020. These reductions were made in an effort to preserve liquidity after the further deterioration of commodity prices following the outbreak of COVID-19.Our operational employees and contractors and certain support personnel have been classified as an essential critical infrastructure workforce by government authorities and continue to work in their plant, rig, field and office locations under our COVID-19 Health and Safety Plan that includes protocols for reporting of illness, self-quarantine, hygiene, applying social distancing to minimize close contact between workers, cleaning or disinfection of workspaces and protection of emergency response personnel. We have not experienced any operational slowdowns due to COVID-19 among our workforce.

~~Our Operations~~

natural gas basins. We conduct our operations on properties that we hold through fee interests, mineral leases and other contractual arrangements. ~~We are the largest private oil and natural gas~~Approximately 65% of our mineral acreage ~~holder in California, with interests in 2.2 million net mineral acres, approximately 60% of which~~ is held in fee and ~~17%~~the remainder is leased. Of our leased acreage, approximately 50% is held by ~~production. Our oil~~production and ~~gas leases have~~the remainder is subject to lease expiration if initial producing wells are not drilled within a specified period of time. The primary terms ~~ranging~~of our leases range from one to ten years. ~~Once production commences, the~~The terms of these leases are typically extended ~~on the producing acreage through the end of their producing life.~~ upon achieving commercial production for so long as such production is maintained.

As a result of our large mineral acre position held in fee, we generally have the flexibility to ~~shut~~shut-in wells in ~~wells~~response to a low commodity price environment while retaining our oil and gas leases which are held by production. With our significant land holdings in California, we have undertaken initiatives to obtain additional value from our surface acreage, including pursuing renewable energy opportunities.

We also own or control a network of integrated infrastructure that complements our operations including gas processing plants, oil and gas gathering systems, power plants and other related assets. Our strategically located infrastructure helps us maximize the value generated from our production. Beyond our essential role in supplying Californians with oil, natural gas, NGLs and electricity, our 2030 Sustainability Goal for carbon is to design and permit California’s first carbon capture and sequestration system by mid-decade which is expected to reduce carbon emissions associated with our operations and significantly extend the productive life of our Elk Hills field.

We respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and gas reserves we can economically produce over the longer term. With our significant land holdings in California, we have undertaken initiatives to obtain additional value from our surface acreage, including pursuing renewable energy opportunities, agricultural activities and other commercial uses.

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and ~~production~~operating costs. We record a share of production and reserves to recover a portion of such capital and ~~production~~operating costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and ~~production~~operating costs that we incur on their behalf, (ii) for our share of contractually defined base production and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and ~~production~~operating costs. However, our net economic benefit is greater when product prices are higher. These contracts represented approximately ~~20%~~16% of our net production for the ~~quarter~~three months ended ~~June 30, 2020.~~March 31, 2021.

In line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under such contracts in our condensed consolidated statements of operations as opposed to reporting only our share of those costs. We report the proceeds from production designed to recover our partners' share of such costs (cost recovery) in our revenues. Our reported production volumes reflect only our share of the total volumes produced, including cost recovery, which is less than the total volumes produced under the PSC-type contracts. This difference in reporting full operating and general and administrative costs but only our net share of production equally inflates our oil, natural gas and NGL sales revenue, general and administrative expenses and operating costs ~~and~~but has no effect on our net results.

Marketing Arrangements

We own a large and geographically diverse portfolio of assets that generate the following revenue streams:

Crude Oil — We sell ~~nearly~~almost all of our crude oil into the California refining markets, which offer ~~relatively~~ favorable pricing for comparable grades relative to other U.S. regions. Substantially all of our crude oil production is connected ~~via our gathering systems,~~ to third-party pipelines and California refining markets ~~and we have not encountered any significant issues with storage or reaching these markets during the industry downturn.~~via our gathering systems. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.

Although California state policies actively promote and subsidize renewable energy, the demand for oil and natural gas in California remains strong. California is heavily reliant on imported sources of energy, with approximately ~~72%~~70% of oil and 90% of natural gas consumed in 2019 imported from outside the state. Nearly all of the imported oil arrives via supertanker, mostly from foreign locations. As a result, California refiners have typically purchased crude oil at international waterborne-based Brent prices. ~~We continue to receive a premium in comparison to other comparable grades due to the demand for our product in the state of California.~~ We believe that the limited crude transportation infrastructure from other parts of the U.S. into California will continue to contribute to higher realizations than most other U.S. oil markets for comparable grades.

Natural Gas — We sell all of our natural gas not used in our operations into the California markets on a ~~monthly~~daily basis at ~~market-based~~average monthly index pricing. Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity ~~from~~in the market and producing areas. Transportation capacity influences prices because California imports ~~approximately~~more than 90% of its natural gas from other states and Canada. As a result, we typically enjoy ~~favorable~~higher netback pricing relative to out-of-state producers due to lower transportation costs on the delivery of our natural gas. Changes in natural gas prices have a smaller impact on our operating results than changes in oil prices as only approximately 25% of our total equivalent production volume and ~~even a smaller percentage~~approximately 11% of our revenue isfrom oil, natural gas and NGL sales are from natural gas.

In addition to selling our produced natural gas, we also ~~use~~purchase natural gas for use in steam generation for our steamfloods and power generation. ~~As a result, the~~The positive impact of higher natural gas prices is partially offset by higher operating costs of our steamflood projects and power generation, but higher prices still have a net positive effect on our operating results due to ~~higher revenue.~~more volumes sold than used. Conversely, lower natural gas prices lower ~~the~~our operating costs but have a net negative effect on our financial results.

We currently have ~~sufficient firm~~ transportation capacity contracts to transport ~~our natural gas, where some capacity volumes vary by month. We sell virtually all~~the majority of our natural gas ~~production under individually negotiated contracts using market-based pricing on a monthly or shorter basis.~~volumes until September 2023.

Natural Gas Liquid (NGL) — NGL price realizations are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints and seasonality can magnify ~~pricing~~price volatility.

Our earnings are also affected by the performance of our complementary ~~processing and power-generation assets.~~natural gas-processing plants. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the NGLs. The efficiency with which we extract liquids from the wet gas stream affects our operating results. Our natural ~~gas processing~~gas-processing plants also facilitate access to third-party delivery points near the Elk Hills field.

We currently have a pipeline delivery contract to transport 6,500 barrels per day of NGLs to ~~market.~~market through March 2023. Our contract to deliver NGLs requires us to cash settle any shortfall between the committed quantities and volumes actually ~~delivered. In connection with another pipeline delivery contract that we assumed from Occidental, we made a one-time deficiency payment~~shipped. We have thus far met all of ~~$20 million in April 2020 when the contract expired.~~our shipping commitments under this contract. We sell virtually all of our NGLs using index-based pricing. Our NGLs are generally sold pursuant to contracts that are renewed annually. Approximately ~~28%~~30% of our NGLs are sold to export markets.

Electricity — Part of the electrical output from the Elk Hills power plant is used by Elk Hills and other nearby fields, which reduces field operating costs and ~~increases reliability.~~provides a reliable source of power. We sell the excess electricity generated to ~~the grid and~~ a local ~~utility.~~utility, other third parties and the grid. The power sold to the utility is subject to ~~agreements~~an agreement through the end of 2023, which ~~include~~includes a monthly capacity payment plus a variable payment based on the quantity of power purchased each month. Any excess capacity not sold to other third parties is sold to the wholesale power market. The prices obtained for excess power impact our earnings but generally by ~~an insignificant~~a relatively small amount.

~~Derivatives~~Hedging

Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ~~Hedging Activities~~ensure our financial strength and liquidity by protecting our cash flows.

Our Revolving Credit Facility requires us to maintain hedges on a minimum amount of crude oil production, determined semi-annually, of no less than (i) 75% of our reasonably anticipated oil production from our proved reserves for the first 24 months after the closing of the Revolving Credit Facility, which occurred on the Effective Date, and (ii) 50% of our reasonably anticipated oil production from our proved reserves for a period from the 25th month through the 36th month after the same date. The Revolving Credit Facility specifies the forms of hedges and prices (which can be prevailing prices) that must be used for a portion of those hedges.

We ~~opportunistically seek strategic hedging transactions~~must also maintain acceptable commodity hedges for no less than 50% of the reasonably anticipated oil production from our proved reserves for at least 24 months following the date of delivery of each reserve report if our leverage ratio is greater than 2.00:1.00. If our leverage ratio is less than 2.00:1.00, then the minimum amount of hedges that we are required to ~~help protect our cash flow, operating margin and capital program~~maintain is reduced from ~~both the cyclical nature~~50% to 33%. Currently, we may not hedge more than 85% of commodity prices and interest rate movements while maintaining adequate liquidity and improving our ability to comply with our debt covenants. We can give no assurance that our hedging programs will be adequate to accomplish our objectives. In early March 2020, in response to the rapid fall in commodity prices, we monetized allreasonably anticipated total forecasted production of ~~our~~ crude oil, ~~hedges in place~~natural gas and natural gas liquids from our oil and gas properties for April 2020 forward with our counterparties, except for certain hedges held by our BSP JV, for approximately $63 million to enhance our liquidity. As of June 30, 2020, we did not have any commodity hedges covering our share of production.

The Senior DIP Credit Agreement requires us to enter into hedging arrangements covering at least 25% of our share of expected crude oil production for the next twelve months. On July 24, 2020, we entered into various derivative instruments through July 2021 to satisfy this requirement. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not accounted for as cash-flow or fair-value hedges.

~~Development Joint Ventures~~

~~We have~~ a number of joint ventures that have allowed us to accelerate the development of our assets which provided us with operational and financial flexibility as well as near-term production benefits. The following table summarizes the cumulative investment through June 30, 2020 by our development joint venture partners, before transaction costs:


	~~Cumulative Investment through~~
	~~June 30, 2020~~
	~~(in millions)~~
~~Alpine~~	$	~~231~~
~~Royale~~	17
~~MIRA~~	~~139~~
~~BSP~~	~~200~~
~~Total Capital Investment~~	$	~~587~~

~~For more information on our development joint ventures, please see our most recent Form 10-K for the year ended December 31, 2019.~~

~~Alpine JV~~48-month period.

In ~~July 2019,~~the three months ended March 31, 2021, we ~~entered into~~added hedges on one million barrels of production for the period from April 2021 to March 2022 at a ~~development agreement with Alpine Energy~~weighted-average Brent price of approximately $61 per barrel. See Liquidity and Capital ~~LLC (Alpine). Alpine has committed to invest $320 million, which may be increased to~~Resources below for a ~~total investment of $500 million subject to the mutual~~agreement of the parties. The initial $320 million commitment covers multiple development opportunities and is intended to be invested over a period of up to three years in accordance with a 275-well development plan.current table summarizing our outstanding derivative contracts.

~~On March 27, 2020, Alpine elected to suspend its funding obligations pursuant to~~

Seasonality

While certain aspects of our operations are affected by seasonal factors, such as energy costs, seasonality has not been a contractual right that is triggered if the average NYMEX 12-month forward strip price for Brent crude oil falls below $45 per barrel over a 30-trading day period. The suspension is automatically lifted and Alpine is obligated to renew funding at such time as the average price exceeds that threshold over any 30-trading day period. If prices remain below the threshold for over 100 consecutive trading days, the development phase may be terminated by us, subject to agreement by Alpine.

~~Ares JV~~

~~In February 2018,~~material driver of changes in our wholly owned subsidiary California Resources Elk Hills, LLC (CREH) entered into a midstream joint venture with ECR, a portfolio company of Ares. The Ares JV holds the Elk Hills power plant (a 550-megawatt natural gas fired power plant) and a 200 MMcf/d cryogenic gas processing plant. We hold 50% of the Class A common interests and 95.25% of the Class C common interests in the Ares JV. ECR holds 50% of the Class A common interests, 100% of the Class B preferred interests and 4.75% of the Class C common interests. As contemplated by the terms of the joint venture, CREH purchases electricity, steam and gas processing services from the Ares JV (subject to certain limitations, including certain geographical limitations) in exchange for monthly capacity payments pursuant to the terms of a Commercial Agreement, the proceeds of which will be used by the Ares JV to make distributions as contemplated by the Second Amended and Restated Limited Liability Company Agreement of Elk Hills Power, LLC. CREH also serves as the operator of the Ares JV and provides operational and support services in exchange for a monthly fee pursuant to a Master Services Agreement.

~~For more information on the Ares JV, see~~ ~~Part I, Item 1~~ – ~~Financial Statements, Note 6 Joint Ventures.~~ ~~For more information on the Settlement Agreement, see~~ ~~Part I, Item 1~~ – ~~Financial Statements, Note 1 Basis of Presentation.~~quarterly results.

Fixed and Variable Costs

Our ~~production~~operating costs include (1) variable costs that fluctuate with production levels and (2) fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. A certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program. However, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. ~~As a result of the~~The measures taken to address the ~~recent~~ industry downturn in the prior year demonstrate that we ~~continue~~can significantly reduce our operating costs in response to prevailing market conditions. We further believe ~~approximately one-third~~that a significant portion of our operating costs are ~~fixed~~variable over the ~~life cycle~~lifecycle of our ~~fields and the remaining two-thirds costs are variable.~~fields. We actively manage our fields to optimize production and minimize ~~costs. When we see growth~~costs in a ~~field, we increase capacities~~safe and ~~similarly, when a field nears the end of its economic life, we manage the costs while it remains economically viable to produce.~~responsible manner throughout their lifecycles.

3225

Production and Prices

The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 and ~~2019:~~2020:


							Successor	Predecessor
		Three months ended June 30,			Six months ended June 30,				Three months ended March 31,	Three months ended March 31,
		2020	2019	2020	2019		2021	2020
Oil (MBbl/d)	Oil (MBbl/d)					Oil (MBbl/d)
San Joaquin Basin	San Joaquin Basin	41	52	44	54	San Joaquin Basin	38	47
Los Angeles Basin	Los Angeles Basin	27	23	26	24	Los Angeles Basin	20	26
Ventura Basin	Ventura Basin	2	4	3	4	Ventura Basin	2	4

Total	Total	70	79	73	82	Total	60	77
NGLs (MBbl/d)	NGLs (MBbl/d)					NGLs (MBbl/d)
San Joaquin Basin	San Joaquin Basin	13	15	14	14	San Joaquin Basin	12	14

Ventura Basin	Ventura Basin	—	1	—	1	Ventura Basin	—	—

Total	Total	13	16	14	15	Total	12	14
Natural gas (MMcf/d)	Natural gas (MMcf/d)					Natural gas (MMcf/d)
San Joaquin Basin	San Joaquin Basin	148	164	151	164	San Joaquin Basin	135	152
Los Angeles Basin	Los Angeles Basin	2	3	2	3	Los Angeles Basin	1	2
Ventura Basin	Ventura Basin	3	6	4	6	Ventura Basin	4	6
Sacramento Basin	Sacramento Basin	21	30	22	29	Sacramento Basin	20	23
Total	Total	174	203	179	202	Total	160	183

Total Net Production (MBoe/d)	Total Net Production (MBoe/d)	112	129	117	131	Total Net Production (MBoe/d)	99	121

Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent (Boe) per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

For the three months ended ~~June 30, 2020~~March 31, 2021 compared to the same period in ~~2019,~~2020, total daily production decreased by approximately 1722 MBoe/d or ~~13%~~18%. The decrease in production largely ~~represented base decline resulting~~resulted from ~~low internal~~limited drilling and capital investment during the ~~temporary shut~~prior 12 months. Our average drilling rigs decreased from 7 in the three months ended March 31, 2020 to 1 rig in the three months ended March 31, 2021. In addition, production was also negatively impacted by 1 MBoe/d in the first quarter of ~~certain wells beginning in March~~2021 compared to 2020 ~~and the effect~~due to downtime at one of ~~the May 2019 partial divestiture of the Lost Hills field. The shut in wells and the Lost Hills divestiture reduced~~ our ~~second quarter 2020 net production by 7 MBoe/d. Due to the lower price environment, our~~gas processing plants. Our PSC-type contracts ~~positively~~negatively impacted our oil production in the ~~second~~first quarter of ~~2020~~2021 by ~~over 5~~approximately 3 MBoe/d compared to the same period in ~~2019. Excluding the effect of the Lost Hills transaction, the shut in wells and the PSC effects, our base decline was below 12%, which is in line with our range of stated base decline rates.~~

~~For the six months ended June 30,2020~~2020. Our total daily production decreased by approximately 15% compared to the same period in 2019, total daily production decreased by approximately 14 MBoe/d or 11%. The decrease in production largely represented base decline resulting from low internal capital investment, shut in production and2020 after excluding the ~~effect~~impact of the May 2019 partial divestiture of the Lost Hills field. The shut in wells and the Lost Hills divestiture reduced our net production for the six months ended June 30, 2020 by 7 MBoe/d. Due to the lower price environment, our PSC-type contracts ~~positively impacted~~and unscheduled downtime at one of our oil production in the first half of 2020 by over 4 MBoe/d compared to the same period in 2019. Excluding the effect of the Lost Hills transaction, the shut in wells and the PSC effects, our base decline was approximately 8%.natural gas processing plants.

3326

The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX for our products for the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 and ~~2019:~~2020:


									Successor				Predecessor
		Three months ended June 30,													Three months ended March 31,			Three months ended March 31,
		2020					2019					2021					2020
		Price		Realization	Price		Realization		Price		Realization		Price			Realization
Oil ($ per Bbl)	Oil ($ per Bbl)							Oil ($ per Bbl)
Brent	Brent	$	33.27		$	68.32		Brent	$	61.10			$	50.96

Realized price without hedge	Realized price without hedge	$	30.27	91%	$	68.77	101%	Realized price without hedge	$	60.81	100%		$	50.78		100%
Settled hedges	Settled hedges	0.55			1.89			Settled hedges	(7.08)				4.72
Realized price with hedge	Realized price with hedge	$	30.82	93%	$	70.66	103%	Realized price with hedge	$	53.73	88%		$	55.50		109%

WTI	WTI	$	27.85		$	59.82		WTI	$	57.84			$	46.17
Realized price without hedge	Realized price without hedge	$	30.27	109%	$	68.77	115%	Realized price without hedge	$	60.81	105%		$	50.78		110%
Realized price with hedge	Realized price with hedge	$	30.82	111%	$	70.66	118%	Realized price with hedge	$	53.73	93%		$	55.50		120%

NGLs ($ per Bbl)	NGLs ($ per Bbl)							NGLs ($ per Bbl)
Realized price (% of Brent)	Realized price (% of Brent)	$	21.05	63%	$	27.82	41%	Realized price (% of Brent)	$	48.77	80%		$	29.28		57%
Realized price (% of WTI)	Realized price (% of WTI)	$	21.05	76%	$	27.82	47%	Realized price (% of WTI)	$	48.77	84%		$	29.28		63%

Natural gas	Natural gas							Natural gas
NYMEX ($/MMBtu)	NYMEX ($/MMBtu)	$	1.77		$	2.66		NYMEX ($/MMBtu)	$	2.72			$	2.05

Realized price without hedge ($/Mcf)	Realized price without hedge ($/Mcf)	$	1.65	93%	$	2.33	88%	Realized price without hedge ($/Mcf)	$	3.29	121%		$	2.25		110%
Settled hedges	Settled hedges	0.08			0.03			Settled hedges	(0.04)				0.10
Realized price with hedge ($/Mcf)	Realized price with hedge ($/Mcf)	$	1.73	98%	$	2.36	89%	Realized price with hedge ($/Mcf)	$	3.25	119%		$	2.35		115%

Six months ended June 30, 2020
2020 2019
Price Realization Price Realization
Oil ($ per Bbl)
Brent $ 42.12 $ 66.11
Realized price without hedge $ 41.02 97% $ 65.97 100%
Settled hedges 2.74 1.93
Realized price with hedge^(a)
$ 43.76 104% $ 67.90 103%
WTI $ 37.01 $ 57.36
Realized price without hedge $ 41.02 111% $ 65.97 115%
Realized price with hedge $ 43.76 118% $ 67.90 118%
NGLs ($ per Bbl)
Realized price (% of Brent) $ 25.18 60% $ 34.97 53%
Realized price (% of WTI) $ 25.18 68% $ 34.97 61%
Natural gas
NYMEX ($/MMBtu) $ 1.91 $ 2.95
Realized price without hedge ($/Mcf) $ 1.96 103% $ 2.87 97%
Settled hedges 0.09 (0.01)
Realized price with hedge ($/Mcf) $ 2.05 107% $ 2.86 97%

(a) Prices for the first six months of 2020 exclude the effect of $63 million of proceeds received in the first quarter of 2020 from settling derivative contracts with counterparties prior to maturity.

Oil — Brent index and realized prices without hedge settlements were ~~lower~~higher in ~~both~~ the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 compared to the same prior-year period due to ~~the combination of the supply increase caused by the Saudi-Russia price war and~~a recovery in oil demand from the severe demand decline caused by ~~COVID-19.~~COVID-19 in 2020. Prices collapsed in March 2020 at the beginning of the pandemic and have since improved as a result of easing restrictions and the significant production curtailments by OPEC members and Russia. Further, ~~our realizations without hedge were~~most producers in other nations also curtailed production and significantly ~~affected~~reduced their capital investments in ~~the three months ended June 30,~~response to COVID-19 in 2020, and to a lesser extent in the six months ended June 30, 2020, primarily due to the unprecedented global oversupply of oil and Saudi Arabia's price cuts for oil to the U.S. and other markets in April 2020. These two events led to lower crude realizations for foreign oil importedwhich continued into ~~California and depressed prices for native California crude.~~2021.

NGLs — Prices for NGLs ~~decreased from~~increased for the three months ended March 31, 2021 compared to the same ~~prior-year~~ period in 2020 as supply ~~associated with high gas-producing basins~~in 2020 outpaced ~~steady~~ demand, causing lower ~~domestic~~ NGL prices in the ~~three~~first quarter of 2020. In the first quarter of 2021, producers continued to curtail production and ~~six months ended June 30, 2020. We continue~~the tighter supply resulted in higher benchmark prices and price realizations as compared to ~~receive premium prices for NGLs relative to national hub prices.~~the same prior year period.

Natural Gas — Our natural gas realized prices were ~~lower~~higher in ~~both~~ the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 than the comparable ~~periods~~period of ~~2019. The decrease was~~2020 due to increased ~~nationwide~~ natural gas ~~production and lower~~ demand ~~resulting~~in the nationwide markets. This was a significant change from the first quarter of 2020 in which demand decreased as a result of shelter-in-place orders related to ~~COVID-19 that began in March 2020. Prices were also negatively impacted by lower supply constraints on the SoCalGas system in 2020 compared to the same period in the prior year.~~

~~Balance Sheet Analysis~~

~~The following table sets forth changes in our balance sheet between June 30, 2020 and December 31, 2019:~~

June 30, December 31,
2020 2019
(in millions)
Cash $ 126 $ 17
Trade receivables $ 132 $ 277
Inventories $ 61 $ 67
Other current assets, net $ 84 $ 130
Property, plant and equipment, net $ 4,449 $ 6,352
Other assets $ 78 $ 115
Current portion of long-term debt $ 5,083 $ 100
Current deferred gain and issuance costs, net $ 125 $ —
Accounts payable $ 196 $ 296
Accrued liabilities $ 355 $ 313
Long-term debt $ — $ 4,877
Deferred gain and issuance costs, net $ — $ 146
Other long-term liabilities $ 719 $ 720
Mezzanine equity $ 828 $ 802
Equity attributable to common stock $ (2,452) $ (389)
Equity attributable to noncontrolling interests $ 76 $ 93

~~Cash~~ ~~— Cash at June 30, 2020 and December 31, 2019 included restricted cash of $21 million and $3 million, respectively. See~~ ~~Liquidity and Capital Resources~~ ~~for our cash flow analysis.~~

~~Trade receivables~~ ~~— The decrease in trade receivables was largely driven by lower realized product prices and lower production volumes in June 2020 compared to December 2019.~~

~~Other current assets, net~~ — The decrease in other current assets, net was primarily due to the sale of our crude oil hedge positions resulting in a decrease in the fair value of the current portion of our derivative assets. Additionally, in March 2020, we recorded an $11 million impairment on capital investments to be recovered from our joint interest partners solely from production.COVID-19.

~~Property, plant and equipment, net~~ ~~— The decrease in property, plant and equipment, net primarily reflected the $1.7 billion impairment~~Statements of certain of our proved and unproved properties recorded in the first quarter of 2020, depreciation, depletion, and amortization (DD&A) and to a lesser extent sales of certain royalty interests and non-core assets in the first quarter of 2020. The decrease was partially offset by capital investments including the planned major maintenance at our Elk Hills power plant. For further detail about the asset impairment, see ~~Part I, Item 1~~ – ~~Financial Statements, Note 14 Asset Impairments~~.Operations Analysis

~~Other assets~~ ~~— Other assets decreased primarily due to utilizing parts~~We adopted an accounting convenience date of October 31, 2020 for the ~~planned major maintenance~~application of ~~our Elk Hills power plant as well as a decrease in operating lease assets due to releasing drilling rigs in the first quarter of 2020.~~

~~Current portion of long-term debt~~ ~~— The increase in the current portion of long-term debt was~~fresh start accounting. As a result of the ~~reclassification~~application of fresh start accounting and the implementation of the Plan, our ~~long-term debt~~results of operations for the Successor period may not be comparable with that of the Predecessor period. Accordingly, “black-line” financial statements are presented to ~~current as described in~~ ~~Part I, Item 1 – Financial Statements, Note 5 Debt~~.

~~Current portion of deferred gain~~distinguish between the Predecessor and ~~issuance costs, net~~ ~~— The increase in the current portion of deferred gain and issuance costs, net was primarily a result of reclassifying capitalized costs associated with our long-term debt~~Successor companies. References to ~~current.~~

~~Accounts payable~~ ~~— The decrease in accounts payable was due to lower amounts payable to vendors following the reduction of our capital plan in the second quarter of 2020 compared~~"Predecessor” refer to the ~~fourth quarter of 2019.~~

~~Accrued liabilities~~ ~~— The increase in accrued liabilities primarily related~~Company for periods ended on or prior to ~~an increase in accrued interest as a result of our failure~~October 31, 2020 and references to make certain interest payments and property tax payments during the second quarter of 2020 compared to balances due as of the fourth quarter of 2019. These amounts were partially offset by the bonus payments to employees made in the first quarter of 2020 with respect to 2019 performance as well as a decrease in activities of the Alpine JV following their suspension of further capital funding due to low commodity prices.

~~Long-term debt~~ ~~— The decrease in long-term debt resulted from the reclassification of long-term debt to current as of June 30, 2020.~~

~~Deferred gain and issuance costs, net~~ ~~— The decrease in deferred gain and issuance costs, net resulted from the reclassification of costs associated with our long-term debt to current as of June 30, 2020.~~

~~Mezzanine equity~~ ~~— The increase in mezzanine equity primarily resulted from the preferred return~~“Successor” refer to the ~~Class B interests held by the noncontrolling interest partner in our Ares JV.~~

~~Equity attributable~~Company for periods subsequent to ~~common stock~~ ~~— Equity attributable to common stock decreased primarily as a result of the net loss in the six months ended June 30,~~October 31, 2020.

~~Statements of Operations Analysis~~

Results of Oil and Gas Operations

The following ~~represents~~table includes key operating data for our oil and gas operations, excluding certain corporate ~~items,~~expenses, on a per Boe basis for the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 and ~~2019:~~2020:

Three months ended
June 30, Six months ended
June 30,
2020 2019 2020 2019
Production costs $ 12.42 $ 19.62 $ 14.99 $ 19.54
Production costs, excluding effects of PSC-type contracts^(a)
$ 12.00 $ 17.98 $ 14.33 $ 17.99
Field general and administrative expenses^(b)
$ 1.17 $ 1.28 $ 1.08 $ 1.27
Field depreciation, depletion and amortization^(b)
$ 7.82 $ 9.55 $ 8.98 $ 9.47
Field taxes other than on income^(b)
$ 2.84 $ 2.39 $ 2.96 $ 2.53


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
Energy operating costs(a)	$	4.70	$	3.71
Gas processing costs	0.53		0.67
Non-energy operating costs(b)	13.10		13.00
Operating costs	$	18.33	$	17.38

Operating costs, excluding effects of PSC-type contracts(c)	$	16.72	$	16.48
Field general and administrative expenses(d)	$	0.89	$	1.09
Field depreciation, depletion and amortization(d)(e)	$	5.14	$	10.05
Field taxes other than on income(d)	$	3.46	$	3.08

(a)Energy operating costs include purchases of fuel gas and electricity used in our operations and internal costs to produce electricity used in our fields.

(b)Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.

(c)As described in the Operations section, the reporting of our PSC-type contracts creates a difference between reported ~~production~~operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel ~~production~~operating costs. These amounts represent our ~~production~~operating costs after adjusting for this difference.

~~(b)~~(d)Excludes corporate expenses.

(e)Field depreciation, depletion and amortization decreased in the three months ended March 31, 2021 from the same period in 2020 primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the fresh start valuation of our property, plant and equipment.

Consolidated Results of Operations

The following ~~represents key operating data for~~table presents our consolidated results of operations and key financial measures for the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 and ~~2019:~~2020:

Three months ended
June 30, Six months ended
June 30,
2020 2019 2020 2019
(in millions)
Oil and natural gas sales $ 245 $ 578 $ 675 $ 1,179
Net derivative (loss) gain from commodity contracts (4) 21 75 (68)
Other revenue 35 54 99 232
Production costs (127) (230) (319) (463)
General and administrative expenses (69) (79) (129) (162)
Depreciation, depletion and amortization (88) (121) (207) (239)
Asset impairments — — (1,736) —
Taxes other than on income (38) (36) (79) (77)
Exploration expense (2) (10) (7) (20)
Other expenses, net (67) (55) (136) (203)
Interest and debt expense, net (85) (98) (172) (198)
Net gain on early extinguishment of debt — 20 5 26
Other non-operating expenses (47) (3) (61) (10)
(Loss) income before income taxes (247) 41 (1,992) (3)
Income tax — — — —
Net (loss) income (247) 41 (1,992) (3)
Net income attributable to noncontrolling interests (24) (29) (75) (52)
Net (loss) income attributable to common stock $ (271) $ 12 $ (2,067) $ (55)
Adjusted net (loss) income^(a)
$ (202) $ (14) $ (210) $ 17
Adjusted EBITDAX^(a)
$ 19 $ 255 $ 270 $ 556
Effective tax rate — % — % — % — %

~~(a)Adjusted net (loss) income and adjusted EBITDAX are non-GAAP measures. See the~~ ~~Non-GAAP Financial Measures~~ ~~section below for reconciliations to their nearest U.S. GAAP equivalent.~~


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
(in millions)
Oil, natural gas and NGL sales	$	432	$	430
Net derivative (loss) gain from commodity contracts	(213)		79
Trading revenue	98		45
Electricity sales	33		13
Other revenue	13		6
Operating costs	(164)		(192)
General and administrative expenses	(48)		(60)
Depreciation, depletion and amortization	(52)		(119)
Asset impairments	(3)		(1,736)
Taxes other than on income	(40)		(41)
Exploration expense	(2)		(5)
Trading costs	(61)		(24)
Electricity cost of sales	(24)		(16)
Transportation costs	(12)		(13)
Other expenses, net	(30)		(16)
Reorganization items	(2)		—
Interest and debt expense, net	(13)		(87)
Net gain on early extinguishment of debt	(2)		5
Gain on asset divestitures	2		—
Other non-operating expenses	(1)		(14)
Loss before income taxes	(89)		(1,745)
Income tax	—		—
Net loss	(89)		(1,745)
Net income attributable to noncontrolling interests	(5)		(51)
Net loss attributable to common stock	$	(94)	$	(1,796)

Three months ended ~~June 30,~~March 31, 2021 vs. 2020 ~~vs. 2019~~

Oil, ~~and~~ natural gas and NGL sales — Oil, ~~and~~ natural gas and NGL sales, ~~decreased 58%, or $333~~excluding the impact of settled hedges, were $432 million for the three months ended ~~June 30, 2020~~March 31, 2021, which is an increase of $2 million compared to $430 million for the same period of ~~2019~~2020. The increase was due to ~~lower~~higher realized prices, ~~and~~which was partially offset by lower production, as reflected in the following table:

Note: See Production and Prices for index prices, realizations and production volumes for comparative periods.

The effect of settled hedges is not included in the table above. ~~Net proceeds from~~Payments for settled hedges were $5$39 million for the three months ended ~~June 30, 2020~~March 31, 2021 compared to ~~net~~ proceeds of ~~$14~~$98 million, including $63 million of proceeds from derivative contracts sold prior to maturity, for the same period of ~~2019, which had a negative impact of $9 million on our total revenue between periods.~~2020. Including the effect of settled hedges, our oil, ~~and~~ natural gas and NGL revenue decreased by ~~$342~~$135 million or ~~58%~~26% compared to the same prior-year period.


Delaware						46-5670947
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)


Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock	CRCQQ*CRC	N/A*New York Stock Exchange


	Page
Part I
Item 1	Financial Statements (unaudited)	2
	Condensed Consolidated Balance Sheets	2
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Statements of Comprehensive Income (Loss)	4
	Condensed Consolidated Statements of Equity	5
	Condensed Consolidated Statements of Cash Flows	76
	Notes to the Condensed Consolidated Financial Statements	87
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2621
	General	2621
	Business Environment and Industry Outlook	2622
	Operations	2923
	~~Development Joint Ventures~~Seasonality	3125
	Fixed and Variable Costs	3225
	Production and Prices	33
	~~Balance Sheet Analysis~~	3526
	Statements of Operations Analysis	3628
	Liquidity and Capital Resources	4331
	~~2020~~2021 Capital Program	47
	~~Seasonality~~	4733
	Lawsuits, Claims, Commitments and Contingencies	4734
	Significant Accounting and Disclosure Changes	4834
	Forward-Looking Statements	4935
Item 3	Quantitative and Qualitative Disclosures About Market Risk	5137
Item 4	Controls and Procedures	5237

Part II
Item 1	Legal Proceedings	5338
Item 1A	Risk Factors	5338
Item 5	Other Disclosures	5938
Item 6	Exhibits	6039


	June 30,		December 31,
	2020		2019
CURRENT ASSETS
Cash	$	126	$	17
Trade receivables	132		277
Inventories	61		67
Other current assets, net	84		130
Total current assets	403		491
PROPERTY, PLANT AND EQUIPMENT	22,914		22,889
Accumulated depreciation, depletion and amortization	(18,465)		(16,537)
Total property, plant and equipment, net	4,449		6,352
OTHER ASSETS	78		115
TOTAL ASSETS	$	4,930	$	6,958


CURRENT LIABILITIES
Current portion of long-term debt	5,083		100
Current portion of deferred gain and issuance costs, net	125		—
Accounts payable	196		296
Accrued liabilities	355		313
Total current liabilities	5,759		709
LONG-TERM DEBT	—		4,877
DEFERRED GAIN AND ISSUANCE COSTS, NET	—		146
OTHER LONG-TERM LIABILITIES	719		720
MEZZANINE EQUITY
Redeemable noncontrolling interests	828		802
EQUITY
Preferred stock (20 million shares authorized at $0.01 par value) 0 shares outstanding at June 30, 2020 and December 31, 2019	—		—
Common stock (200 million shares authorized at $0.01 par value) outstanding shares (June 30, 2020 - 49,453,297 and December 31, 2019 - 49,175,843)	—		—
Additional paid-in capital	5,008		5,004
Accumulated deficit	(7,437)		(5,370)
Accumulated other comprehensive loss	(23)		(23)
Total equity attributable to common stock	(2,452)		(389)
Equity attributable to noncontrolling interests	76		93
Total equity	(2,376)		(296)
TOTAL LIABILITIES AND EQUITY	$	4,930	$	6,958


	Three months ended June 30, 2020
	Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity
Balance, March 31, 2020	$	5,006	$	(7,166)	$	(23)	$	(2,183)	$	88	$	(2,095)
Net loss	—		(271)		—		(271)		(6)		(277)

Distributions to noncontrolling interest holders	—		—		—		—		(6)		(6)
Share-based compensation, net	2		—		—		2		—		2





Balance, June 30, 2020	$	5,008	$	(7,437)	$	(23)	$	(2,452)	$	76	$	(2,376)


	Six months ended June 30, 2020
	Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity
Balance, December 31, 2019	$	5,004	$	(5,370)	$	(23)	$	(389)	$	93	$	(296)
Net (loss) income	—		(2,067)		—		(2,067)		15		(2,052)

Distributions to noncontrolling interest holders	—		—		—		—		(32)		(32)
Share-based compensation, net	4		—		—		4		—		4



Balance, June 30, 2020	$	5,008	$	(7,437)	$	(23)	$	(2,452)	$	76	$	(2,376)


	Three months ended March 31, 2021 (Successor)
	Common Stock		Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity
Balance, December 31, 2020	$	1	$	1,268	$	(123)	$	(8)	$	1,138	$	44	$	1,182
Net (loss) income(a)	—		—		(94)		—		(94)		5		(89)

Distributions to noncontrolling interest holders	—		—		—		—		—		(14)		(14)
Share-based compensation	—		2		—		—		2		—		2






Balance, March 31, 2021	$	1	$	1,270	$	(217)	$	(8)	$	1,046	$	35	$	1,081


	Three months ended June 30, 2019
	Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity
Balance, March 31, 2019	$	4,989	$	(5,409)	$	(6)	$	(426)	$	137	$	(289)
Net loss	—		12		—		12		—		12
Contributions from noncontrolling interest holders, net	—		—		—		—		—		—
Distributions to noncontrolling interest holders	—		—		—		—		(8)		(8)
Issuance of common stock	—		—		—		—		—		—
Other comprehensive income			—		1		1		—		1
Share-based compensation, net	5		—		—		5		—		5



Balance, June 30, 2019	$	4,994	$	(5,397)	$	(5)	$	(408)	$	129	$	(279)


	Six months ended June 30, 2019
	Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity
Balance, December 31, 2018	$	4,987	$	(5,342)	$	(6)	$	(361)	$	114	$	(247)
Net loss	—		(55)		—		(55)		(5)		(60)
Contributions from noncontrolling interest holders, net	—		—		—		—		49		49
Distributions to noncontrolling interest holders	—		—		—		—		(29)		(29)

Other comprehensive income	—		—		1		1		—		1
Share-based compensation, net	7		—		—		7		—		7

Balance, June 30, 2019	$	4,994	$	(5,397)	$	(5)	$	(408)	$	129	$	(279)


	Outstanding Principal					Interest Rate		Security
	June 30, 2020		December 31, 2019
Credit Agreements	($ in millions)
2014 Revolving Credit Facility	$	731	$	518	LIBOR plus 3.25%-4.00% ABR plus 2.25%-3.00%		Shared First-Priority Lien
2017 Credit Agreement	1,300		1,300		LIBOR plus 4.75% ABR plus 3.75%		Shared First-Priority Lien
2016 Credit Agreement	1,000		1,000		LIBOR plus 10.375% ABR plus 9.375%		First-Priority Lien
Second Lien Notes
Second Lien Notes	1,808		1,815		8%		Second-Priority Lien
Senior Notes
5% Senior Notes due 2020	—		100		5%		Unsecured
5.5% Senior Notes due 2021	100		100		5.5%		Unsecured
6% Senior Notes due 2024	144		144		6%		Unsecured
Total Debt	$	5,083	$	4,977
Less: Current Portion of Long-Term Debt	(5,083)		(100)
Total Long-Term Debt	$	—	$	4,877


	June 30, 2020^(a)		December 31, 2019
	(in millions)
Deferred gain	$	176	$	211
Issuance costs and original issue discounts	(51)		(65)
Net deferred gain and issuance costs	$	125	$	146


	Equity Attributable to Noncontrolling Interest										Mezzanine Equity - Redeemable Noncontrolling Interests
	Ares JV		BSP JV		Total		Ares JV		Elk Hills Carbon JV		Total
	(in millions)
Balance, December 31, 2019	$	—	$	93	$	93	$	802	$	—	$	802
Net income (loss) attributable to noncontrolling interests	3		12		15		61		(1)		60
Contributions from noncontrolling interest holders, net	—		—		—		—		2		2

Distributions to noncontrolling interest holders	(3)		(29)		(32)		(36)		—		(36)
Balance, June 30, 2020	$	—	$	76	$	76	$	827	$	1	$	828

Balance, December 31, 2018	$	15	$	99	$	114	$	756	$	—	$	756
Net (loss) income attributable to noncontrolling interests	(6)		1		(5)		57		—		57
Contributions from noncontrolling interest holders, net	—		49		49		—		—		—

Distributions to noncontrolling interest holders	(4)		(25)		(29)		(36)		—		(36)
Balance, June 30, 2019	$	5	$	124	$	129	$	777	$	—	$	777


June 30, 2020
Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented in the Balance Sheet
Assets:	(in millions)
Other current assets, net	$	7	$	—	$	7
Other assets	—		—		—

Liabilities:
Accrued liabilities	—		—		—

Total derivatives	$	7	$	—	$	7


	Six months ended June 30,
	2020						2019
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
	(in millions)
Service cost	$	1	$	2	$	—	$	2
Interest cost	1		2		1		3
Expected return on plan assets	—		—		(1)		(1)
Recognized actuarial loss	—		—		1		1
Settlement loss	—		—		1		—
Total	$	2	$	4	$	2	$	5



	Balance Sheet Location	June 30, 2020		December 31, 2019
		(in millions)		(in millions)
Right-of-Use Assets
Operating lease, net	Other assets	$	45	$	59
Finance lease, net	PP&E	1		2
Total right-of-use assets		$	46	$	61

Lease Liabilities
Current
Operating lease	Accrued liabilities	$	14	$	27
Finance lease	Accrued liabilities	1		1
Long-term
Operating lease	Other long-term liabilities	33		37
Finance lease	Other long-term liabilities	—		1
Total lease liabilities		$	48	$	66


Condensed Consolidating Balance Sheets
As of June 30, 2020 and December 31, 2019
(in millions)

	June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total current assets	$	22	$	341	$	68	$	(28)	$	403
Investments in consolidated subsidiaries	3,156		(53)		—		(3,103)		—
Total property, plant and equipment, net	24		3,972		453		—		4,449
Other assets	1		64		13		—		78
TOTAL ASSETS	$	3,203	$	4,324	$	534	$	(3,131)	$	4,930

Total current liabilities	5,409		371		7		(28)		5,759


Other long-term liabilities	159		557		3		—		719
Amounts due to (from) affiliates	87		(88)		1		—		—
Mezzanine equity	—		—		828		—		828
Total equity	(2,452)		3,484		(305)		(3,103)		(2,376)
TOTAL LIABILITIES AND EQUITY	$	3,203	$	4,324	$	534	$	(3,131)	$	4,930


Condensed Consolidating Statements of Operations
For the three and six months ended June 30, 2020 and 2019
(in millions)

	Three months ended June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	253	$	94	$	(71)	$	276
Total costs	55		357		50		(71)		391
Non-operating (loss) income	(135)		3		—		—		(132)
NET (LOSS) INCOME	(190)		(101)		44		—		(247)
Net income attributable to noncontrolling interests	—		—		(24)		—		(24)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	$	(190)	$	(101)	$	20	$	—	$	(271)


Condensed Consolidating Statements of Cash Flows
For the six months ended June 30, 2020 and 2019
(in millions)

	Six months ended June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net cash (used in) provided by operating activities	$	(338)	$	277	$	154	$	—	$	93
Net cash provided by (used in) investing activities	1		(28)		—		—		(27)
Net cash provided by (used in) financing activities	340		(153)		(144)		—		43
Increase in cash	3		96		10		—		109
Cash—beginning of period	—		6		11		—		17
Cash—end of period	$	3	$	102	$	21	$	—	$	126


	Successor		Predecessor
	Three months ended March 31, 2021		Three months ended March 31, 2020
(in millions)
Capital investments	$	(27)	$	(30)
Changes in capital investment accruals	5		(19)
Proceeds from divestitures	2		41
Other	—		(4)
Net cash used in investing activities	$	(20)	$	(12)


		August-September 2020		Q4 2020		Q1 2021		Q2 2021		July 2021			Q2 2021		Q3 2021		Q4 2021		1H 2022		2H 2022		January - October 2023
Sold Calls:
Sold Calls												Sold Calls
Barrels per day	Barrels per day	4,950		4,800		4,500		4,500		4,200		Barrels per day	33,537		36,688		37,037		33,842		27,773		17,758
Weighted-average price per barrel	Weighted-average price per barrel	$	48.05	$	48.05	$	48.05	$	48.05	$	48.05	Weighted-average price per barrel	$	48.73	$	50.47	$	60.75	$	60.00	$	58.62	$	58.01


Purchased Puts:
Purchased Puts												Purchased Puts
Barrels per day	Barrels per day	9,900		9,600		9,000		9,000		8,400		Barrels per day	37,872		36,943		35,820		33,842		27,773		17,758
Weighted-average price per barrel	Weighted-average price per barrel	$	40.00	$	40.00	$	40.00	$	40.00	$	40.00	Weighted-average price per barrel	$	40.00	$	40.18	$	40.19	$	40.00	$	40.00	$	40.00

Sold Puts:
Sold Puts												Sold Puts
Barrels per day	Barrels per day	4,950		4,800		4,500		4,500		4,200		Barrels per day	15,149		14,647		14,193		3,416		2,674		—
Weighted-average price per barrel	Weighted-average price per barrel	$	30.00	$	30.00	$	30.00	$	30.00	$	30.00	Weighted-average price per barrel	$	31.41	$	30.00	$	32.00	$	32.00	$	32.00	$	—

Swaps:
Swaps												Swaps
Barrels per day	Barrels per day	6,600		6,400		6,000		6,000		5,600		Barrels per day	9,639		10,063		10,922		7,763		6,386		5,919
Weighted-average price per barrel	Weighted-average price per barrel	$	44.75	$	44.75	$	44.75	$	44.75	$	44.75	Weighted-average price per barrel	$	46.35	$	49.09	$	51.11	$	48.17	$	46.34	$	47.57


	2021 Target	Three months ended March 31, 2021
	(in millions)
Drilling	$105 - $120	$	13
Capital workovers	35 - 40	7
Infrastructure, corporate and other	45 - 50	7
Total	$185 - $210	$	27


3.1			Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 to Registrant’s ~~Current Report~~Registration Statement on Form ~~8-K~~8-A filed ~~June 3, 2016~~October 27, 2020 and incorporated herein by reference).

3.2			Amended and Restated Bylaws of California Resources Corporation (filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form 8-A filed October 27, 2020 and incorporated herein by reference).

4.1			Indenture, dated January 20, 2021, by and among California Resources Corporation, the guarantors and Wilmington Trust, National Association (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed ~~November 10, 2015~~January 21, 2021 and incorporated herein by reference).

4.2			First Supplemental Indenture, dated January 20, 2021, by and among California Resources Corporation, the guarantors, Elk Hills Power, LLC, EHP Midco Holding Company, LLC, EHP Topco Holding Company, LLC and Wilmington Trust, National Association (filed as Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed January 21, 2021 and incorporated herein by reference).

10.1			Second Amendment to Forbearance Agreement, dated as of June 30, 2020, by and among the Company, the subsidiary guarantors party thereto, certain Lenders identified therein, JPMorgan Chase Bank, N.A., as Administrative Agent, a Lender and a Letter of Credit Issuer, and Bank of America, N.A., a Lender and a Letter of Credit Issuer California Resources Corporation 2021 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed J ~~uly~~2 ~~, 2020~~January 22, 2021 and incorporated herein by reference).

10.2			~~Second~~ ~~Amendment to~~ ~~Forbearance~~Form of California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit Award for Non-Employee Directors Grant Agreement ~~dated as of~~ ~~June~~ ~~30, 2020,~~ ~~by and~~ ~~among the Company, as the Borrower,~~ ~~the subsidiary guarantorspartythereto,thevariousLendersidentified therein~~ ~~and~~ ~~The Bank of New York Mellon Trust Company,N.A.,~~as ~~Administrative Agent~~ (filed as Exhibit ~~10.2~~10.45 to the Registrant’s ~~Current~~Annual Report on Form ~~8-K~~10-K filed ~~July~~2 , ~~2020~~March 11, 2021 and incorporated herein by reference).

10.3			~~Second Amendment to~~ ~~Forbearance Agreement, dated as~~Form of ~~June~~ ~~30,~~ ~~2020, by~~California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit Award Term and ~~among the Company, as the Borrower, the~~ ~~subsidiaryguarantors~~ ~~party thereto, the various Lenders identified~~ ~~therein~~ ~~and~~ ~~The Bank of New YorkMellonTrustCompany,~~ ~~N.A., as Administrative Agent~~Conditions (filed as Exhibit ~~10.3~~10.46 to ~~Registrant's Current~~the Registrant’s Annual Report on Form ~~8-K~~10-K filed Ju ~~ly 2~~, ~~2020~~March 11, 2021 and incorporated herein by reference).

10.4			~~Restructuring Support Agreement, dated as~~Form of ~~July 15, 2020, by~~California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit Award Term and ~~among the Company and the other parties named therein~~Conditions (filed as Exhibit ~~10.1~~10.47 to the ~~Company’s Current~~Registrant’s Annual Report on Form ~~8-K~~10-K filed ~~July 16, 2020)~~March 11, 2021 and incorporated herein by reference).

10.5			~~Senior Secured Superpriority Debtor-in-Possession Revolving Credit Facility Commitment Letter, dated as~~Form of ~~July 15, 2020, by and among~~ California Resources Corporation ~~certain of its subsidiaries~~2021 Long Term Incentive Plan Performance Stock Unit Award Term and ~~JPMorgan Chase Bank, N.A.~~Conditions (filed as Exhibit ~~10.2~~10.48 to the ~~Company’s Current~~Registrant’s Annual Report on Form ~~8-K~~10-K filed ~~July 16, 2020)~~March 11, 2021 and incorporated herein by reference).

10.6			~~Settlement and Assumption~~Employment Agreement ~~dated as of July 15, 2020,~~ by and ~~among the Company,~~between Mark A. McFarland and California Resources ~~Elk Hills, LLC, Elk Hills Power, LLC, ECR Corporate Holdings GP LLC, ECR I, L.P., SSF IV Energy I AIV 1, L.P., SSF IV Energy I AIV 2, L.P., AEOF ECR Holdings, L.P., and ECR Corporate Holdings, L.P.~~Corporation, dated March 22, 2021 (filed as Exhibit ~~10.3~~10.1 to the ~~Company’s~~Registrant's Current Report on Form 8-K filed ~~July 16, 2020)~~March 22, 2021 and incorporated herein by reference).

10.7			~~Backstop Commitment Agreement, dated as of July 15, 2020, among California Resources Corporation and the Backstop Parties hereto (filed as Exhibit 10.1~~ First Amendment to the ~~Company's Current Report on Form 8-K filed July 1~~7 ~~, 2020).~~

~~10.8~~			~~Senior Secured Superpriority Debtor-in-Possession~~ Credit Agreement, dated as of ~~July 23, 2020,~~May 7, 2021, by and among California Resources Corporation, as the Borrower, the several lenders from time to time parties ~~hereto,~~thereto and ~~JPMorgan Chase Bank,~~Citibank, N.A., as Administrative Agent, Collateral Agent and ~~as Sole Lead Arranger and Bookrunner~~an Issuing Bank (filed as Exhibit 10.1 to the ~~Company’s~~Registrant's Current Report on Form 8-K filed ~~July~~ ~~24,~~ ~~2020).~~May 10, 2021 and incorporated herein by reference.)

~~10.9~~			~~Junior~~ ~~Secured Superpriority Debtor-in-Possession Credit Agreement dated as of July 2~~3 ~~, 2020, among California Resources Corporation, as the Borrower, the several lenders from time to time parties hereto, and~~ ~~AlterDomusProductsCorp.,~~ ~~as Administrative Agent(filed~~ as ~~Exhibit10.2~~to ~~theCompany’s Current Report on Form 8-K filed July 2~~4 ~~, 2020).~~

~~10.10~~			Amended and Restated Restructuring Support Agreement, dated as of July 24, 2020, by and among California Resources Corporation, certain of its subsidiaries and the Consenting Parties (as defined therein)~~(filed as Exhibit 10.~~3 ~~to the Company’s Current Report on Form 8-K filed July 2~~4 ~~, 2020).~~

~~10.11~~			~~Amended and Restated Backstop Commitment Agreement, dated as of July 24, 2020, by and among California Resources Corporation, certain of its subsidiaries and the Backstop Parties (as defined therein)(filed as Exhibit 10.~~4 ~~to the Company’s Current Report on Form 8-K filed July 2~~4 ~~, 2020).~~











31.1*			Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*			Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*			Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


101.INS*			Inline XBRL Instance Document.

101.SCH*			Inline XBRL Taxonomy Extension Schema Document.

101.CAL*			Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB*			Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*			Inline XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF*			Inline XBRL Taxonomy Extension Definition Linkbase Document.

104			Cover Page Interactive Data File (formatted in inline XBRL and contained in Exhibits 101).


DATE:	~~August 6, 2020~~May 13, 2021	/s/ ~~Roy~~Noelle M. ~~Pineci~~Repetti
		~~Roy~~Noelle M. ~~Pineci~~Repetti
		~~Executive~~ Vice President ~~- Finance~~and Controller
		(Principal Accounting Officer)