UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ___________

Commission file number 001-36478

California Resources Corporation

(Exact name of registrant as specified in its charter)

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

27200 Tourney Road, Suite 200

Santa Clarita, California 91355

(Address of principal executive offices) (Zip Code)

(888) 848-4754

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Exchange Act:

Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock	CRC	New York Stock Exchange

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of 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, as of the last practicable date.

The number of shares of common stock outstanding, prior to CRC's emergence from bankruptcy as of October 27, 2020 was 49,498,227. Following CRC's emergence from bankruptcy, the number of shares of CRC's common stock outstanding as of October 27, 2020 was 83,319,721.

California Resources Corporation and Subsidiaries

Table of Contents

	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	7
	Notes to the Condensed Consolidated Financial Statements	8
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
	General	34
	Business Environment and Industry Outlook	36
	Operations	37
	Development Joint Ventures	40
	Fixed and Variable Costs	42
	Production and Prices	43
	Balance Sheet Analysis	45
	Statements of Operations Analysis	47
	Liquidity and Capital Resources	57
	2020 Capital Program	61
	Regulation of the Oil and Natural Gas Industry	61
	Seasonality	61
	Lawsuits, Claims, Commitments and Contingencies	62
	Significant Accounting and Disclosure Changes	62
	Forward-Looking Statements	63
Item 3	Quantitative and Qualitative Disclosures About Market Risk	65
Item 4	Controls and Procedures	66
Part II
Item 1	Legal Proceedings	67
Item 1A	Risk Factors	67
Item 5	Other Disclosures	73
Item 6	Exhibits	74

1

PART I    FINANCIAL INFORMATION

Item 1Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of September 30, 2020 and December 31, 2019

(dollars in millions, except share data)

(DEBTOR-IN-POSSESSION: Entity Operating Under Chapter 11)

	September 30,		December 31,
	2020		2019
CURRENT ASSETS
Cash	$	122	$	17
Trade receivables	155		277
Inventories	61		67
Other current assets, net	82		130
Total current assets	420		491
PROPERTY, PLANT AND EQUIPMENT	22,915		22,889
Accumulated depreciation, depletion and amortization	(18,555)		(16,537)
Total property, plant and equipment, net	4,360		6,352
OTHER ASSETS	76		115
TOTAL ASSETS	$	4,856	$	6,958

CURRENT LIABILITIES
Current portion of long-term debt	—		100
Debtor-in-possession financing	733		—
Accounts payable	221		296
Accrued liabilities	240		313
Total current liabilities	1,194		709
LONG-TERM DEBT	—		4,877
DEFERRED GAIN AND ISSUANCE COSTS, NET	—		146
OTHER LONG-TERM LIABILITIES	727		720
LIABILITIES SUBJECT TO COMPROMISE	4,516		—
MEZZANINE EQUITY
Redeemable noncontrolling interests	692		802
EQUITY
Preferred stock (20 million shares authorized at $0.01 par value) no shares outstanding at September 30, 2020 and December 31, 2019	—		—
Common stock (200 million shares authorized at $0.01 par value) outstanding shares (September 30, 2020 - 49,498,227 and December 31, 2019 - 49,175,843)	—		—
Additional paid-in capital	5,148		5,004
Accumulated deficit	(7,466)		(5,370)
Accumulated other comprehensive loss	(23)		(23)
Total equity attributable to common stock	(2,341)		(389)
Equity attributable to noncontrolling interests	68		93
Total equity	(2,273)		(296)
TOTAL LIABILITIES AND EQUITY	$	4,856	$	6,958

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

2

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

For the three and nine months ended September 30, 2020 and 2019

(dollars in millions, except share data)

(DEBTOR-IN-POSSESSION: Entity Operating Under Chapter 11)

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
REVENUES
Oil and natural gas sales	$	312	$	541	$	987	$	1,720
Net derivative gain (loss) from commodity contracts	—		37		75		(31)
Marketing and trading revenue	50		62		109		230
Electricity sales	43		38		75		88
Other revenue	4		3		12		17
Total revenues	409		681		1,258		2,024
COSTS
Production costs	141		221		460		684
General and administrative expenses	64		66		193		228
Depreciation, depletion and amortization	89		118		296		357
Asset impairments	—		—		1,736		—
Taxes other than on income	42		42		121		119
Exploration expense	2		5		9		25
Marketing and trading costs	35		45		67		170
Electricity cost of sales	17		18		47		51
Transportation costs	10		10		31		30
Other expenses, net	22		8		75		33
Total costs	422		533		3,035		1,697
OPERATING (LOSS) INCOME	(13)		148		(1,777)		327
NON-OPERATING (LOSS) INCOME
Reorganization items, net	66		—		66		—
Interest and debt expense, net	(28)		(95)		(200)		(293)
Net gain on early extinguishment of debt	—		82		5		108
Other non-operating expenses	(32)		(8)		(93)		(18)
(LOSS) INCOME BEFORE INCOME TAXES	(7)		127		(1,999)		124
Income tax	—		—		—		—
NET (LOSS) INCOME	(7)		127		(1,999)		124
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
Mezzanine equity	(25)		(30)		(85)		(87)
Equity	3		(3)		(12)		2
Net income attributable to noncontrolling interests	(22)		(33)		(97)		(85)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	$	(29)	$	94	$	(2,096)	$	39
Net (loss) income attributable to common stock per share
Basic (includes return from noncontrolling interest)	$	2.20	$	1.89	$	(39.64)	$	0.78
Diluted (includes return from noncontrolling interest)	$	2.20	$	1.89	$	(39.64)	$	0.77

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

3

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Comprehensive Income (Loss)

For the three and nine months ended September 30, 2020 and 2019

(dollars in millions)

(DEBTOR-IN-POSSESSION: Entity Operating Under Chapter 11)

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
Net (loss) income	$	(7)	$	127	$	(1,999)	$	124
Net income attributable to noncontrolling interests	(22)		(33)		(97)		(85)
Other comprehensive income:
Reclassification of realized losses on pension and postretirement benefits to income(a)	—		—		—		1
Comprehensive (loss) income attributable to common stock	$	(29)	$	94	$	(2,096)	$	40

(a) No associated tax for the three and nine months ended September 30, 2020 and 2019. See Note 11 Pension and Postretirement Benefit Plans for additional information.

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

4

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Equity

For the three and nine months ended September 30, 2020

(dollars in millions)

(DEBTOR-IN-POSSESSION: Entity Operating Under Chapter 11)

	Three months ended September 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, June 30, 2020	$	5,008	$	(7,437)	$	(23)	$	(2,452)	$	76	$	(2,376)
Net loss	—		(29)		—		(29)		(3)		(32)
Distributions to noncontrolling interest holders	—		—		—		—		(5)		(5)
Share-based compensation, net	2		—		—		2		—		2
Return from noncontrolling interest holders	138		—		—		138		—		138
Balance, September 30, 2020	$	5,148	$	(7,466)	$	(23)	$	(2,341)	$	68	$	(2,273)

	Nine months ended September 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	—		(2,096)		—		(2,096)		12		(2,084)
Distributions to noncontrolling interest holders	—		—		—		—		(37)		(37)
Share-based compensation, net	6		—		—		6		—		6
Return from noncontrolling interest holders	138		—		—		138		—		138
Balance, September 30, 2020	$	5,148	$	(7,466)	$	(23)	$	(2,341)	$	68	$	(2,273)

Note:     The above tables exclude amounts related to redeemable noncontrolling interests reported in mezzanine equity. See Note 7 Joint Ventures for more information about our noncontrolling interests and a settlement agreement entered into with one of our noncontrolling interest holders in the third quarter of 2020 where the modification of terms was treated as a return from noncontrolling interest holders.

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

5

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Equity

For the three and nine months ended September 30, 2019

(dollars in millions)

(DEBTOR-IN-POSSESSION: Entity Operating Under Chapter 11)

	Three months ended September 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, June 30, 2019	$	4,994	$	(5,397)	$	(5)	$	(408)	$	129	$	(279)
Net income	—		94		—		94		3		97
Distributions to noncontrolling interest holders	—		—		—		—		(32)		(32)
Warrant	2		—		—		2		—		2
Share-based compensation, net	4		—		—		4		—		4
Balance, September 30, 2019	$	5,000	$	(5,303)	$	(5)	$	(308)	$	100	$	(208)

	Nine months ended September 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 income (loss)	—		39		—		39		(2)		37
Contributions from noncontrolling interest holders, net	—		—		—		—		49		49
Distributions to noncontrolling interest holders	—		—		—		—		(61)		(61)
Other comprehensive income	—		—		1		1		—		1
Warrant	2		—		—		2		—		2
Share-based compensation, net	11		—		—		11		—		11
Balance, September 30, 2019	$	5,000	$	(5,303)	$	(5)	$	(308)	$	100	$	(208)

Note:     The above tables exclude amounts related to redeemable noncontrolling interests reported in mezzanine equity. See Note 7 Joint Ventures for more information.

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

6

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

For the nine months ended September 30, 2020 and 2019

(dollars in millions)

(DEBTOR-IN-POSSESSION: Entity Operating Under Chapter 11)

	Nine months ended September 30,
	2020		2019
CASH FLOW FROM OPERATING ACTIVITIES
Net (loss) income	$	(1,999)	$	124
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	296		357
Asset impairments	1,736		—
Net derivative (gain) loss from commodity contracts	(75)		31
Net proceeds from settled commodity derivatives	105		68
Net gain on early extinguishment of debt	(5)		(108)
Amortization of deferred gain	(39)		(54)
Reorganization items, net (non-cash)	(125)		—
Reorganization items, net (debtor-in-possession financing costs)	25		—
Dry hole expenses	—		7
Other non-cash charges to income, net	69		60
Changes in operating assets and liabilities, net	153		55
Net cash provided by operating activities	141		540
CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(37)		(393)
Decreases in accrued capital investments	(25)		(49)
Asset divestitures	41		164
Acquisitions	—		(6)
Other	(7)		(7)
Net cash used in investing activities	(28)		(291)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from 2014 Revolving Credit Facility	797		1,749
Repayments of 2014 Revolving Credit Facility	(1,315)		(1,776)
Proceeds from debtor-in-possession facilities	782		—
Repayments of debtor-in-possession facilities	(49)		—
Debtor-in-possession financing costs	(25)		—
Debt repurchases	(3)		(149)
Debt transaction costs	—		(2)
2020 Senior Notes payment	(100)		—
Contributions from noncontrolling interest holders, net	1		49
Distributions paid to noncontrolling interest holders	(95)		(115)
Issuance of common stock	—		3
Shares cancelled for taxes	(1)		(3)
Net cash used in financing activities	(8)		(244)
Increase in cash	105		5
Cash—beginning of period	17		17
Cash—end of period	$	122	$	22

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

7

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

September 30, 2020

(DEBTOR-IN-POSSESSION: Entity Operating Under Chapter 11)

NOTE 1    CHAPTER 11 PROCEEDINGS

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.

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 retention of the vast majority of our receivables, our debt peaked at approximately $6.8 billion in May 2015. Since then, we have engaged in a series of asset sales, joint ventures, debt exchanges, tenders, debt repurchases and other financing transactions to reduce our overall level of debt and improve our balance sheet prior to filing for bankruptcy. As of September 30, 2020, we had outstanding net long-term debt of approximately $5.1 billion, of which $4.4 billion is presented as liabilities subject to compromise on our condensed consolidated balance sheet.

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code (Chapter 11 Cases) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court). The Chapter 11 Cases were jointly administered under the caption In re California Resources Corporation, et al., Case No. 20-33568 (DRJ). We filed with the Bankruptcy Court, on July 24, 2020, the Debtors’ Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code and, on October 8, 2020, the Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (as amended, supplemented or modified, the Plan). On October 13, 2020, the Bankruptcy Court confirmed the Plan, which was conditioned on certain items such as obtaining exit financing. The conditions to effectiveness of the Plan were satisfied and we emerged from Chapter 11 on October 27, 2020 (Effective Date).

During the course of the Chapter 11 Cases, the Bankruptcy Court granted the relief requested in certain motions, 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, which allowed our business operations to continue uninterrupted during the pendency of the Chapter 11 Cases. All transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.

On July 15, 2020, immediately prior to the commencement of the Chapter 11 Cases, we and certain affiliates of Ares Management L.P. (Ares), including ECR Corporate Holdings L.P., a portfolio company of Ares (ECR), entered into a Settlement and Assumption Agreement (Settlement Agreement) related to our midstream joint venture, Elk Hills Power, LLC (Ares JV or Elk Hills Power), which holds our Elk Hills power plant and a cryogenic gas processing plant. On August 25, 2020, the Bankruptcy Court entered an order approving the Settlement Agreement on a final basis. Among other things, the Settlement Agreement included a conversion right, which would be deemed exercised upon our emergence from bankruptcy, allowing us to acquire all (but not less than all) of the equity interests in the Ares JV held by ECR in exchange for secured notes (EHP Notes), approximately 20.8% of our new common stock (Ares Settlement Stock) and $2.5 million in cash. For more information on the Settlement Agreement, see Note 7 Joint Ventures.

8

The commencement of the Chapter 11 Cases constituted 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 New York 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 and together with the 5% Senior Notes due 2020 and 2021 Notes, the Senior 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 were stayed from taking any action against us, including exercising remedies as a result of any event of default. See Note 6 Debt for additional details about our debt.

Joint Plan of Reorganization Under Chapter 11

Pursuant to the Plan, the following transactions occurred on the Effective Date:

•We issued an aggregate of 83.3 million shares of new common stock and reserved 4.4 million shares for issuance upon exercise of the warrants described below;

•We acquired all of the member interests in the Ares JV held by ECR in exchange for the EHP Notes, 17.3 million shares of new common stock and $2.5 million in cash (see Note 6 Debt and Note 7 Joint Ventures for additional information);

•Holders of secured claims under the 2017 Credit Agreement received 22.7 million shares of new common stock in exchange for those claims, and holders of deficiency claims under the 2017 Credit Agreement and all outstanding obligations under the 2016 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received 4.4 million shares of new common stock in exchange for those claims;

•In connection with the Subscription Rights offering and Backstop Commitment Agreement, 34.6 million shares of new common stock were issued in exchange for $446 million (net of a $4 million fee), the proceeds of which were used to pay down our debtor-in-possession financing;

•Our Subscription Rights offering was backstopped by certain creditors who received 3.5 million shares of new common stock as a backstop commitment premium (refer to Note 16 Equity for additional information on the backstop commitment premium);

•The holders of Unsecured Debt Claims (as defined in the Plan) under the 2016 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received Tier 1 Warrants and Tier 2 Warrants (each as defined in the Plan and collectively, Warrants) to purchase up to 2% and 3%, respectively, of our outstanding shares (on a fully diluted basis calculated immediately after the Effective Date), with an initial exercise price of $36.00 per share, which expire on October 27, 2024 and have customary anti-dilution protections (refer to Note 16 Equity for additional information on the Warrants);

•All other general unsecured claims will be paid or disputed in the ordinary course of business; and

•All existing equity interests were cancelled and their holders received no distributions.

As a condition to our emergence, we repaid the outstanding balance of our debtor-in-possession financing with proceeds from our Subscription Rights offering, Backstop Commitment Agreement and a new senior secured revolving credit facility led by Citibank, N.A. We also issued approximately 821,000 shares of new common stock for a debtor-in-possession exit fee. For more information on our debtor-in-possession credit agreements and our post-emergence indebtedness, see Note 6 Debt.

One of the conditions of the Plan was to establish a new Board of Directors, which occurred on October 27, 2020.

9

Changes to our Stock-Based Compensation Programs

As a result of our bankruptcy, the outstanding stock-based awards under our Amended and Restated California Resources Corporation Long-Term Incentive Plan were cancelled on our Effective Date. Any new stock-based awards or compensation plans will be reviewed and approved by our Board of Directors, which includes seven new directors appointed on October 27, 2020.

The cancellation of these stock-based compensation awards resulted in the recognition of all previously unrecognized compensation expense for equity-settled awards and the liability related to our cash-settled awards was eliminated as the participants received no consideration. The net effect of these adjustments was not material to our financial statements.

Changes to the 2020 Compensation Programs in Second Quarter 2020

In the second quarter of 2020, resulting from the unprecedented circumstances affecting the industry and market volatility, we reviewed our incentive programs for the entire workforce to determine whether those programs appropriately aligned compensation opportunities with our 2020 goals and ensured the stability of our workforce. Following this review, effective May 19, 2020, our then Board of Directors approved changes in the variable compensation programs for all participating employees. The previously established target amounts of 2020 variable compensation programs did not change; however, all amounts that vest are being settled in cash. 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. At that time, there were no changes to stock-based compensation awards granted prior to February 2020; however, these pre-2020 awards were subsequently cancelled as part of the Plan. Changes to the variable compensation programs had 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 remained largely the same as the amounts that would have been paid at target prior to the changes. Our future compensation programs will be determined by our new Board of Directors.

Organizational Changes

During the course of the Chapter 11 Cases, we evaluated the structure of our workforce and, in August 2020, we implemented organizational changes that resulted in a reduction of our headcount from 1,250 to approximately 1,100 employees. We believe the steps taken improved and strengthened our business as we emerge from bankruptcy. We recorded a one-time $10 million restructuring charge in the third quarter of 2020. We will continue to evaluate resource levels depending on commodity prices.

10

NOTE 2    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.

We have applied Financial Accounting Standards Board Accounting Standards Codification 852, Reorganizations (ASC 852), in preparing these unaudited condensed consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the petition date (July 15, 2020), distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. As a result, we have segregated liabilities and obligations whose treatment and satisfaction are dependent on the outcome of the Chapter 11 Cases and classified these items as liabilities subject to compromise (LSTC) on our condensed consolidated balance sheet as of September 30, 2020. In addition, we have classified all income, expenses, gains or losses that were incurred or realized as a result of the Chapter 11 Cases subsequent to the petition date as reorganization items, net in our condensed consolidated statements of operations for the period ended September 30, 2020.

Fresh Start Accounting

We believe that we are required to adopt fresh start accounting upon emergence from bankruptcy because (1) the holders of existing voting shares prior to emergence received less than 50% of our new voting shares following our emergence from bankruptcy and (2) the reorganization value of our assets immediately prior to the confirmation of the Plan was less than the post-petition liabilities and allowed claims, which are included in LSTC. Fresh start accounting will be applied as of October 27, 2020, the date we emerged from bankruptcy. Under the principles of fresh start accounting, a new reporting entity is considered to have been created, and, as a result, the reorganization value of the emerging entity is assigned to individual assets and liabilities based on their estimated relative fair values. The process of estimating the fair value of our assets, liabilities and equity upon emergence is currently ongoing. In support of the Plan, the enterprise value of the successor company was estimated and approved by the Bankruptcy Court to be in the range of $2.2 billion to $2.8 billion. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements of the successor entity will not be comparable to the financial statements, including this statement, prepared prior to our Effective Date.

Liabilities Subject to Compromise – Pre-petition Debt

LSTC include our long-term debt and related accrued interest up to the petition date, which represents all of the known or potential obligations resolved in connection with our Plan. Contractual interest on these obligations through September 30, 2020 was $289 million, of which $72 million was not recognized in our financial statements. Upon emergence, all general unsecured claims, other than debt, will be paid or disputed in the ordinary course of business pursuant to the Plan. As of September 30, 2020, LSTC on our condensed consolidated balance sheet included the following:

	September 30,
	2020
	(in millions)
Long-term debt (principal amount):
2017 Credit Agreement	$	1,300
2016 Credit Agreement	1,000
Second Lien Notes	1,808
5.5% Senior Notes due 2021	100
6% Senior Notes due 2024	144
Accrued interest on long-term debt	164
Total liabilities subject to compromise	$	4,516

11

Reorganization Items Related to our Chapter 11 Cases

Reorganization items, net represent the one-time costs related to our reorganization, including the non-cash write-off of unamortized deferred gain, original issue discounts and deferred issuance costs associated with our long-term debt impacted by the Chapter 11 Cases. Legal, professional and other fees incurred subsequent to our petition date through September 30, 2020, including success-based fees, are also included in reorganization items, net as these fees were incurred as a result of the restructuring process. Reorganization items, net consisted of the following for the three and nine months ended September 30, 2020 (in millions):

Unamortized deferred gain and issuance costs, net(a)	$	125
Legal, professional and other, net(b)	(34)
Debtor-in-possession financing costs	(25)
Total reorganization items, net	$	66

(a)Reflects non-cash adjustments necessary to the carrying amount of our long-term debt to state such amounts at face value.

(b)Includes $27 million of unpaid items included in changes in operating assets and liabilities, net on our condensed consolidated statement of cash flows at September 30, 2020.

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 September 30, 2020 and December 31, 2019 and the statements of operations, comprehensive income (loss), equity and cash flows for the three and nine months ended September 30, 2020 and 2019, as applicable. We have eliminated all significant intercompany transactions and accounts. We account for our share of oil and natural gas exploration and development ventures, 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.

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 not misleading. This Form 10-Q 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.

NOTE 3    ACCOUNTING AND DISCLOSURE CHANGES

Recently Adopted Accounting and Disclosure Changes

We adopted the FASB's new rules on current expected credit losses on January 1, 2020, using a modified retrospective approach to the first period in which the guidance is effective. The new rules change 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 in the earlier recognition of an allowance for losses. The adoption of these new rules did not have a significant impact to 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 September 30, 2020 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

NOTE 4    OTHER INFORMATION

Restricted cash — Cash at September 30, 2020 included $24 million which was restricted under agreements to fund operating expenses at one of our joint ventures and 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.

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

	September 30,		December 31,
	2020		2019
	(in millions)
Amounts due from joint interest partners, net(a)	$	41	$	70
Derivative assets	17		39
Prepaid expenses	24		19
Other	—		2
Other current assets, net	$	82	$	130

(a)Both September 30, 2020 and December 31, 2019 balances included a $19 million allowance for credit losses against amounts due from joint interest partners.

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

	September 30,		December 31,
	2020		2019
	(in millions)
Accrued employee-related costs(a)	$	81	$	116
Accrued taxes other than on income	64		57
Accrued interest	1		13
Lease liability	11		28
Asset retirement obligations	28		28
Other(b)	55		71
Accrued liabilities	$	240	$	313

(a)Accrued employee-related costs declined $35 million primarily due to incentive, retention, and severance payments made to employees and former employees.

(b)Other accrued liabilities declined $16 million primarily due to payments to joint interest partners and legal settlement payments. These decreases were partially offset by an increase in accrued legal and professional fees.

Other long-term liabilities — Other long-term liabilities included asset retirement obligations of $507 million and $489 million at September 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.

Supplemental Cash Flow Information

We did not make U.S. federal and state income tax payments during the nine months ended September 30, 2020 and 2019. Interest paid, net of capitalized amounts, totaled $72 million and $290 million for the nine months ended September 30, 2020 and 2019, respectively. Cash paid for legal and professional fees, which is included in reorganization items, net on our condensed consolidated statement of operations for the nine months ended September 30, 2020, totaled $7 million. Non-cash financing activities in 2020 included a $138 million downward adjustment to mezzanine equity related to a Settlement Agreement with one of our joint venture partners. See Note 7 Joint Ventures for more on the Settlement Agreement.

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 6 Debt for the fair value of our debt.

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NOTE 5    INVENTORIES

Inventory is valued at the lower of cost and net realizable value. Finished goods predominantly comprise oil and natural gas liquids (NGLs). Inventories as of September 30, 2020 and December 31, 2019 consisted of the following:

	September 30,		December 31,
	2020		2019
	(in millions)
Materials and supplies	$	58	$	64
Finished goods	3		3
Total	$	61	$	67

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NOTE 6     DEBT

Pre-Emergence Indebtedness

As of September 30, 2020 and December 31, 2019, our short-term debtor-in-possession (DIP) financing and current portion of long-term debt consisted of the following:

	Outstanding Principal				Interest Rate	Security
	September 30, 2020		December 31, 2019
	($ in millions)
Senior DIP Facility	$	83	$	—	LIBOR plus 4.5% ABR plus 3.5%	Secured Superpriority
Junior DIP Facility	650		—		LIBOR plus 9.0% ABR plus 8.0%	Secured Superpriority
Current portion of long-term debt	—		100
Total short-term borrowings and current maturities	$	733	$	100

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

	Outstanding Principal				Interest Rate	Security
	September 30, 2020		December 31, 2019
	($ in millions)
Credit Agreements
2014 Revolving Credit Facility(a)	—		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
Outstanding long-term debt	$	4,352	$	4,977
Less: Current portion of long-term debt	—		(100)
Less: Amounts reclassified to LSTC	(4,352)		—
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.

(a)The proceeds from our debtor-in-possession credit agreements were used to repay the balance of our 2014 Revolving Credit Facility. Borrowings under our debtor-in-possession credit agreements are classified as a current liability on our condensed consolidated balance sheet at September 30, 2020.

As of September 30, 2020, we had letters of credit outstanding of $151 million under the Senior DIP Facility. As of December 31, 2019, we had letters of credit outstanding under the 2014 Revolving Credit Facility of $165 million. These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other items.

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Related to the Chapter 11 Cases, we recorded a non-cash gain of $125 million to write off all of the related unamortized deferred gain, discount and debt issuance costs as a reorganization item, net in our condensed consolidated statements of operations for the three and nine months ended September 30, 2020. As of December 31, 2019, net deferred gain and issuance costs were $146 million, consisting of deferred gain and issuance costs of $211 million and $65 million, respectively.

Note Repurchases

In the 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. We did not repurchase any notes in the second or third quarters of 2020. In the nine months ended September 30, 2019, we repurchased approximately $229 million in face value of our Second Lien Notes for $149 million in cash resulting in a pre-tax gain of $108 million, including the effect of unamortized deferred gain and issuance costs.

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 were 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 provides for a 30-day grace period, which expired on July 15, 2020. We did not make the July 15, 2020 interest payment and commenced bankruptcy proceedings.

Commencement of Bankruptcy Proceedings

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 pre-petition long-term debt. Any efforts to enforce payment obligations related to the acceleration of our long-term debt were automatically stayed by the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement were subject to the applicable provisions of the Bankruptcy Code. See Note 1 Chapter 11 Proceedings for more information on our Chapter 11 Cases.

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Pursuant to the Plan, on the Effective Date, the obligations of the Debtors under each of the following debt instruments were cancelled and the applicable agreements governing such obligations were terminated: (a) the Credit Agreement, dated as of November 17, 2017, among The Bank of New York Mellon Trust Company, N.A., as administrative agent, as amended, restated, supplemented or otherwise modified (the “2017 Term Loan Agreement”); (b) the Credit Agreement, dated as of August 12, 2016, among The Bank of New York Mellon Trust Company, N.A., as administrative agent and collateral agent, as amended, restated, supplemented or otherwise modified (the “2016 Term Loan Agreement”); (c) the Indenture dated as of December 15, 2015, among The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which the 8% Senior Secured Second Lien Notes due 2022 were issued, as amended, supplemented or otherwise modified (the “Second Lien Notes Indenture”); and (d) the Indenture dated as of October 1, 2014, among Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, as trustee, pursuant to which the 5% Senior Notes due 2020, 5.5% Senior Notes due 2021 and 6% Senior Notes due 2024 were issued, as amended, supplemented or otherwise modified (the “Unsecured Notes Indenture”).

Debtor-in-Possession Credit Agreements

On July 23, 2020, we entered into a Senior Secured Superpriority DIP Credit Agreement with JP Morgan, as administrative agent, and certain other lenders (Senior DIP Credit Agreement), which provided for the senior DIP facility in an aggregate principal amount of up to $483 million (Senior DIP Facility). The Senior DIP Facility included a $250 million revolving facility which was primarily used by us to (i) fund working capital needs, 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. Following a hearing, the Bankruptcy Court entered a final order on August 14, 2020, which approved the Senior DIP Facility on a final basis. The Senior DIP Facility also included (i) a $150 million letter of credit facility which was used to redeem letters of credit outstanding under the 2014 Revolving Credit Facility as issued under the Senior DIP Facility, and (ii) $83 million of term loan borrowings which were used to repay a portion of the 2014 Revolving Credit Facility. The Senior DIP Facility allowed for the issuance of an additional $35 million of letters of credit.

On July 23, 2020, we entered into a Junior Secured Superpriority DIP Credit Agreement with Alter Domus, as administrative agent, and certain lenders (Junior DIP Credit Agreement), which provided for a junior DIP facility in an aggregate principal amount of $650 million (Junior DIP Facility and together with the Senior DIP Facility, the DIP Facilities). 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, which would constitute an event of default. If an event of default occurs or is continuing, the applicable administrative agent may accelerate repayment of the indebtedness outstanding and/or pursue other remedies authorized under the Senior DIP Facility or the Junior DIP Facility.

Borrowings under the Senior DIP Facility bear interest at the London interbank offered rate (LIBOR) plus 4.5% for LIBOR loans and the alternative base rate (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.

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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 was repaid in full and terminated on the Effective Date using proceeds borrowed under our new Revolving Credit Facility discussed below. The Junior DIP Facility was also repaid in full and terminated on the Effective Date using (i) $200 million from the Second Lien Term Loan discussed below and (ii) $450 million from the subscription rights offering discussed in Note 1 Chapter 11 Proceedings.

Post-Emergence Indebtedness

Revolving Credit Facility

On October 27, 2020, we entered into a Credit Agreement with Citibank, N.A., as administrative agent, and certain other lenders. This credit agreement currently consists of a $540 million senior revolving loan facility (Revolving Credit Facility), which we are permitted to increase if we obtain additional commitments from new or existing lenders. Our Revolving Credit Facility also includes a sub-limit of $200 million for the issuance of letters of credit. The revolving commitments are subject to an automatic reduction if certain conditions are not met by April 2021.

On the Effective Date, we borrowed $225 million under the Revolving Credit Facility to refinance our DIP Facilities, replace our existing letters of credit and pay certain costs, fees and expenses related to the other transactions consummated on the Effective Date. Our initial borrowings included $118 million used to cash collateralize on an interim basis certain letters of credit that were outstanding under our Senior DIP Facility. We expect that these letters of credit will be transitioned into our new Revolving Credit Facility and will no longer be cash collateralized. In addition, we had unrestricted cash of $72 million on the Effective Date. The proceeds of all or a portion of the Revolving Credit Facility may be used for our working capital needs and for other purposes subject to meeting certain criteria.

Security – The lenders have a first-priority lien on a substantial majority of our assets, except assets securing the EHP Notes as discussed below.

Interest Rate – We can elect to borrow at either an adjusted LIBOR rate or an ABR rate, subject to a 1% floor and 2% floor, respectively, plus an applicable margin. The ABR is equal to the highest of (i) the federal funds effective rate plus 0.50%, (ii) the administrative agent prime rate and (iii) the one-month adjusted LIBOR rate plus 1%. The applicable margin is adjusted based on the borrowing base utilization percentage and will vary from (i) in the case of LIBOR loans, 3% to 4% and (ii) in the case of ABR loans, 2% to 3%; provided that in the event that the EHP Notes are not paid in full on or prior to December 31, 2021, the applicable margin will be increased by 0.25% effective as of January 1, 2022 and will be increased by an additional 0.25% at the beginning of each subsequent fiscal quarter until such date on which the EHP Notes are paid in full. The unused portion of the facility is subject to a commitment fee of 0.5% per annum. We also pay customary fees and expenses. Interest on ABR loans is payable quarterly in arrears. Interest on LIBOR loans is payable at the end of each LIBOR period, but not less than quarterly.

Maturity Date – Our Revolving Credit Facility matures 42 months after closing.

Amortization Payments – The Revolving Credit Facility does not include any obligation to make amortizing payments.

Borrowing Base – The borrowing base, currently $1.2 billion, will be redetermined semi-annually in April and October.

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Financial Covenants – Our Revolving Credit Facility includes the following financial covenants:

Ratio	Components	Required Levels	Tested
Consolidated Total Net Leverage Ratio	Ratio of consolidated total secured debt to consolidated EBITDAX(a)	Not greater than 3.00 to 1.00(c)	Quarterly
Current Ratio	Ratio of consolidated current assets to consolidated current liabilities(b)	Not less than 1.00 to 1.00	Quarterly

(a)EBITDAX is calculated as defined in the credit agreement.

(b)The available credit under our Revolving Credit Facility is included in consolidated current assets as part of the calculation of the current ratio.

(c)In the event that the EHP Notes are not paid in full prior to December 31, 2021 (and until the EHP Notes are repaid in full), the Consolidated Total Net Leverage Ratio for the Test Period ending on December 31, 2021 and as of the last day of any Test Period ending thereafter may not exceed 2.50 to 1.00.

Liquidity – We will become subject to a monthly minimum liquidity requirement of $200 million if, as of the date of our scheduled spring 2021 borrowing base redetermination, (a) our liquidity is less than $290 million and (b) we are not able to obtain at least $60 million in additional commitments under our Revolving Credit Facility or through capital markets or other junior financing transactions, for so long as the conditions in (a) and (b) remain unmet.

Other Covenants – Our Revolving Credit Facility includes covenants that, among other things, restrict our ability to incur additional indebtedness, grant liens, make asset sales and investments, repay existing indebtedness, make subsidiary distributions and enter into transactions that would result in fundamental changes. We are also restricted in the amount of cash dividends we can pay on our common stock unless we meet certain covenants included in the credit agreement.

Our Revolving Credit Facility also 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. In addition, for the first 24 months after closing an additional 25% of production from proved reserves needs to be hedged, which may take any form.

We 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. We may not hedge more than 80% of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids from our oil and gas properties for a 48-month period following the date of entry into any commodity hedging contract.

Events of Default and Change of Control – Our Revolving Credit Facility provides for certain events of default, including upon a change of control, as defined in the credit agreement, that entitles our lenders to declare the outstanding loans immediately due and payable, subject to certain limitations and conditions.

Second Lien Term Loan

On October 27, 2020, we entered into a $200 million credit agreement with Alter Domus Products Corp., as administrative agent, and certain other lenders (Second Lien Term Loan). The proceeds were used to refinance our Junior DIP Facility and to pay certain costs, fees and expenses related to the other transactions consummated on the Effective Date.

Security – The lenders have a second-priority lien (junior to the Revolving Credit Facility) on a substantial majority of our assets, except assets securing the EHP Notes as discussed below.

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Interest Rate – We can elect to pay interest at either an adjusted LIBOR rate or ABR rate, subject to a 1% floor and 2% floor, respectively, plus an applicable margin. The ABR rate is equal to the highest of (i) the prime rate, (ii) the federal funds rate effective rate plus 0.5%, and (iii) the one-month adjusted LIBOR rate plus 1%. In the case of an adjusted LIBOR rate election, the applicable margin is 9% per annum if interest is paid in cash and 10.5% per annum if interest is paid-in-kind. Prior to the second anniversary of the closing date of the Second Lien Term Loan, the applicable margin in the case of an ABR rate election is 8% per annum if paid in cash and 9.5% per annum if paid-in-kind, and the applicable margin in the case of an adjusted LIBOR rate election is 9% if paid in cash and 10.5% if paid-in-kind. After the second anniversary of the closing date, the applicable margin is 8% with respect to any ABR loan and 9% with respect to an adjusted LIBOR loan. Interest on ABR loans is paid quarterly in arrears and interest based on the adjusted LIBOR rate is due at the end of each LIBOR period, which can be one, two, three or six months but not less than quarterly. We also pay customary fees and expenses.

Maturity Date – Our Second Lien Term Loan matures five years after the closing date, subject to extension.

Amortization Payments – We are required to make scheduled amortization payments only with respect to extended loans, the terms of such extension to be agreed with the extending lender at the time of such extension.

Repurchases – We are permitted to repurchase our Second Lien Term Loan in open market purchases or tender offers on a non-pro rata basis.

Redemption – We may redeem all or part of our Second Lien Term Loan, at any time prior to the maturity date, at redemption price equal to (i) 100% of the principal amount if redeemed prior to 90 days after closing, (ii) 105% of the principal amount if redeemed after 90 days and before the first anniversary date, (iii) 103% of the principal amount if redeemed on or after the first anniversary date and before the second anniversary date, (iv) 102% of the principal amount if redeemed on or after the second anniversary date and before the third anniversary date, (v) 101% of the principal amount if redeemed on or after the third anniversary date and before the fourth anniversary date, and (vi) at 100% of the principal amount if redeemed in the fifth year.

Financial Covenants – Our Second Lien Term Loan includes the following financial covenants:

Ratio	Components	Required Levels	Tested
Consolidated Total Net Leverage Ratio	Ratio of consolidated total debt to consolidated EBITDAX(a)	Not greater than 3.45 to 1.00(c)	Quarterly
Current Ratio	Ratio of consolidated current assets to consolidated current liabilities(b)	Not less than 0.85 to 1.00	Quarterly

(a)EBITDAX is calculated as defined in the credit agreement.

(b)The available credit under our Revolving Credit Facility is included in consolidated current assets as part of the calculation of the current ratio.

(c)In the event that the EHP Notes are not paid in full prior to December 31, 2021 (and until the EHP Notes are repaid in full), the Consolidated Total Net Leverage Ratio for the Test Period ending on December 31, 2021 and as of the last day of any Test Period ending thereafter may not exceed 2.875 to 1.00.

Liquidity – We will become subject to a monthly minimum liquidity requirement of $170 million if, as of the Spring 2021 Scheduled Redetermination (as defined in the Revolving Credit Facility), (a) our liquidity is less than $247 million and (b) we are not able to obtain at least $51 million in additional commitments under our Revolving Credit Facility or through capital markets or other junior financing transactions, for so long as the conditions in (a) and (b) remain unmet.

Other Covenants – Our Second Lien Term Loan includes covenants that, among other things, restrict our ability to incur additional indebtedness, grant liens, make asset sales and investments, repay existing indebtedness, make subsidiary distributions and enter into transactions that would result in fundamental changes. We are also restricted in the amount of cash dividends we can pay on our common stock unless we meet certain covenants included in the credit agreement.

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Our Second Lien Term Loan also 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 Second Lien Term Loan specifies the forms of hedges and prices (which can be prevailing prices) that must be used. In addition, for the first 24 months after closing an additional 25% of production from proved reserves needs to be hedged, which may take any form.

We must also maintain acceptable commodity hedges hedging 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. We may not hedge more than 80% of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids from our oil and gas properties for a 48-month period following the date of entry into any commodity hedging contract.

Events of Default and Change of Control – Our Second Lien Term Loan provides for certain events of default, including upon a change of control, as defined in the credit agreement, that entitles our lenders to declare the outstanding loans immediately due and payable, subject to certain limitations and conditions. We are subject to a cross-default provision that causes a default under this facility if certain defaults occur under the Revolving Credit Facility or the EHP Notes.

EHP Notes

On the Effective Date, our wholly-owned subsidiary, EHP Midco Holding Company, LLC (Elk Hills Issuer) entered into a Note Purchase Agreement (Note Purchase Agreement) with certain subsidiaries of Ares and Wilmington Trust, N.A. as collateral agent. The $300 million Notes were issued as partial consideration for the Class B Preferred Units, Class A Common Units and Class C Common Units in the Ares JV previously held by ECR (EHP Notes).

The EHP Notes are senior notes due in 2027, and are secured by a first-priority security interest in all of the assets of Elk Hills Power, any third-party offtake contracts for power generated by Elk Hills Power, all of the equity interests of Elk Hills Power held by Elk Hills Issuer and all of the equity interests of Elk Hills Issuer held by its direct parent, EHP Topco Holding Company, LLC, our wholly-owned subsidiary. We and Elk Hills Power have guaranteed, on a joint and several basis, all of the obligations of Elk Hills Issuer under the EHP Notes. The EHP Notes bear an interest rate of 6.0% per annum through the fourth anniversary of issuance, increasing to 7.0% per annum after the fourth anniversary of issuance and to 8.0% per annum after the fifth anniversary of issuance. The EHP Notes may be redeemed at any time prior to their maturity date without payment of premium or penalty.

Fair Value

At September 30, 2020, we estimated the fair value of our DIP Facilities, which are classified as Level 2 in the fair value hierarchy, to approximate their carrying value of $733 million due to their short-term maturities. Our long-term debt at September 30, 2020 was presented as LSTC and will be impaired under the Plan. As of September 30, 2020, we estimated the fair value of our long-term debt to approximate $500 million based on observable inputs in less active markets (Level 2) compared to a carrying value of $4.4 billion. The estimated fair value of our long-term debt, at December 31, 2019, based on prices from known market transactions (Level 1), was approximately $3.8 billion compared to a carrying value of $5.0 billion.

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NOTE 7    JOINT VENTURES

Noncontrolling Interests

The following table presents the changes in noncontrolling interests for our consolidated JVs, prior to our emergence, which are reported in equity and mezzanine equity on the condensed consolidated balance sheets for the nine months ended September 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		9		12		86		(1)		85
Return from noncontrolling interest	—		—		—		(138)		—		(138)
Contributions from noncontrolling interest holders, net	—		—		—		—		1		1
Distributions to noncontrolling interest holders	(3)		(34)		(37)		(58)		—		(58)
Balance, September 30, 2020	$	—	$	68	$	68	$	692	$	—	$	692
Balance, December 31, 2018	$	15	$	99	$	114	$	756	$	—	$	756
Net (loss) income attributable to noncontrolling interests	(9)		7		(2)		87		—		87
Contributions from noncontrolling interest holders, net	—		49		49		—		—		—
Distributions to noncontrolling interest holders	(6)		(55)		(61)		(54)		—		(54)
Balance, September 30, 2019	$	—	$	100	$	100	$	789	$	—	$	789

Ares JV

In February 2018, our wholly-owned subsidiary California Resources Elk Hills, LLC (CREH) entered into a midstream JV 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. On the Effective Date, as required by the Note Purchase Agreement, CREH transferred its ownership of two low temperature separation plants located at the Elk Hills field to Elk Hills Power.

Prior to our Effective Date, we held 50% of the Class A common interest and 95.25% of the Class C common interest in the Ares JV. 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. The Ares JV was 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 purchased electricity 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 were 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 served as the operator of the Ares JV and provided operational and support services in exchange for a monthly fee pursuant to a Master Services Agreement. These agreements became intercompany agreements on the Effective Date and were cancelled as described below.

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As described in Note 1 Chapter 11 Proceedings, we entered into the Settlement Agreement with ECR and Ares which, among other things, changed the liquidation preference for the Class B member interest to $835 million, decreased the preferred return from 13.5% per annum to 9.5% per annum payable at the end of each month, removed the liquidation premium for the Class A common interest and removed the payment of any previously accrued but unpaid preferred distributions plus a make-whole payment that ECR, as the holder of the Class B preferred interests, would otherwise have been entitled to in the event of a redemption transaction. The Settlement Agreement granted us the right (Conversion Right) to acquire all (but not less than all) of the equity interests of Elk Hills Power owned by ECR in exchange for the EHP Notes, Ares Settlement Stock and $2.5 million in cash. The Conversion Right was deemed to have been exercised on the Effective Date.

Although certain provisions in the Settlement Agreement were not effective until certain conditions were met, such as the Bankruptcy Court entering a final order, we determined that the amended terms were substantively different such that the existing Class A common, Class B preferred and Class C common member interests held by ECR were treated as redeemed in exchange for new member interests issued at fair value. The estimated fair value of the new member interests was lower than the carrying value of the existing member interests by $138 million. In accordance with GAAP, the return from noncontrolling interest holders was recorded to additional paid-in capital on our condensed consolidated balance sheet as of September 30, 2020. However, as required by GAAP, the return is included in our earnings per share calculations. See Note 10 Earnings Per Share for adjustments to net income (loss) attributable to common stock which includes a return from noncontrolling interest holders.

We were deemed to have exercised the Conversion Right on the Effective Date and we issued the EHP Notes in the aggregate principal amount of $300 million, Ares Settlement Stock comprising approximately 20.8% (subject to dilution) of the new common stock (Conversion) and $2.5 million in cash. Upon the Conversion, Elk Hills Power became an indirect wholly-owned subsidiary, and Ares and its affiliates ceased to have any direct or indirect interest in Elk Hills Power, other than any interest Ares may have indirectly through its interests in the EHP Notes and Ares Settlement Stock. In connection with the Conversion, Elk Hills Power’s limited liability company agreement was amended and restated.

In connection with the Conversion, on the Effective Date, we entered into a Sponsor Support Agreement dated the Effective Date (Support Agreement) pursuant to which, among other things, the parties agreed that Elk Hills Power will be our primary provider of electricity to, and will be the primary processor of our natural gas produced from, the Elk Hills field, which is already consistent with our current practice.

On the Effective Date, in connection with the Conversion, we terminated: (a) the Commercial Agreement, dated as of February 7, 2018, by and between Elk Hills Power and CREH and (b) the Master Services Agreement, dated as of February 7, 2018, by and between Elk Hills Power and CREH.

Our condensed consolidated statements of operations for all periods presented 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

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 in our condensed consolidated statements of operations for all periods presented.

Elk Hills Carbon JV

In January 2020, we entered into an agreement with OGCI Climate Investments 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 scope and study. The project received financial assistance from the U.S. Department of Energy and project participants include us, Electric Power Research Institute, and Fluor Corporation. We formed Elk Hills Carbon LLC (Elk Hills Carbon JV) with OGCI to assist with the initial funding obligation. OGCI contributed approximately $2 million to the Elk Hills Carbon JV in February 2020.

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Our condensed consolidated statements of operations reflect the operations of the Elk Hills Carbon JV, with OGCI's share of net income (loss) reported in net income attributable to noncontrolling interests for all periods presented. OGCI's redeemable noncontrolling interests are reported in mezzanine equity due to an optional redemption feature.

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 was triggered when the average NYMEX 12-month forward strip price for Brent crude oil fell below $45 per barrel over a 30-trading day period. The suspension may be lifted by mutual consent. As of September 30, 2020, funding for the initial development phase has not re-started.

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 our most recent Form 10-K for the year ended December 31, 2019.

NOTE 8    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 September 30, 2020 and December 31, 2019 were not material to our condensed consolidated balance sheets as of such dates. 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 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 on July 15, 2020 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, government authorities may determine to continue actions brought under regulatory powers.

On October 13, 2020, the Bankruptcy Court confirmed our Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code, which was conditioned on certain items such as obtaining exit financing. On October 27, 2020 the conditions to effectiveness of the Plan were satisfied and we emerged from Chapter 11 on the Effective Date. Upon effectiveness of the Plan, the automatic stay discussed above no longer applies to ongoing judicial or administrative proceedings.

NOTE 9    DERIVATIVES

We use a variety of derivative instruments in implementing our hedging program to protect our cash flow, operating margin and capital program from the cyclical nature 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.

We did not have any derivative instruments designated as accounting hedges as of and during the three and nine months ended September 30, 2020 and 2019. 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.

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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.

The Senior DIP Credit Agreement required 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 17, 2020, the Bankruptcy Court authorized us to engage in hedging activities. We entered into various derivative instruments, as shown in the table below, to satisfy this requirement.

We held the following Brent-based crude oil contracts as of September 30, 2020:

	Q4 2020		Q1 2021		Q2 2021		July 2021
Sold Calls:
Barrels per day	4,800		4,500		4,500		4,200
Weighted-average price per barrel	$	48.05	$	48.05	$	48.05	$	48.05
Purchased Puts:
Barrels per day	18,600		18,000		9,000		8,400
Weighted-average price per barrel	$	44.84	$	45.00	$	40.00	$	40.00
Sold Puts:
Barrels per day	13,800		13,500		4,500		4,200
Weighted-average price per barrel	$	36.52	$	36.67	$	30.00	$	30.00
Swaps:
Barrels per day	6,400		6,000		6,000		5,600
Weighted-average price per barrel	$	44.75	$	44.75	$	44.75	$	44.75

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.

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 timing of the redemption of BSP's preferred interest.

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The following tables present the fair values on a recurring basis (at gross and net) of our outstanding commodity derivatives as of September 30, 2020 and December 31, 2019:

September 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	$	24	$	(7)	$	17
Other assets	—		—		—
Liabilities:
Accrued liabilities	(9)		7		(2)
Total derivatives	$	15	$	—	$	15

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

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 three months ended September 30, 2020 and 2019, we reported no change in fair value on these contracts in other non-operating expenses on our consolidated statements of operations. For the nine months ended September 30, 2020 and 2019, we reported no change in fair value and a loss of $4 million, respectively, on these contracts in other non-operating expenses on our condensed 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 recognized fair value changes on derivative instruments each reporting period in net derivative gain (loss) from commodity contracts on our condensed consolidated statements of operations for the three and nine months ended September 30, 2020 and 2019. 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.

NOTE 10    EARNINGS PER SHARE

Upon our emergence from bankruptcy on October 27, 2020, as discussed in Note 1 Chapter 11 Proceedings, our then common and preferred stock, including contracts on our equity, were cancelled and new common stock and Warrants were issued. The per share amounts disclosed below would be materially different if our emergence from bankruptcy had occurred on or before September 30, 2020.

We compute basic and diluted earnings per share (EPS) using the two-class method required for participating securities. Certain of our restricted and performance stock awards are considered participating securities because they have non-forfeitable dividend rights at the same rate as our common stock.

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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 shares related to unvested restricted stock awards. For diluted EPS, the basic shares outstanding are adjusted by adding all potentially dilutive securities.

The following table presents the calculation of basic and diluted EPS, prior to our emergence, for the three and nine months ended September 30, 2020 and 2019:

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
Basic EPS calculation	(in millions, except per-share amounts)
Net (loss) income	$	(7)	$	127	$	(1,999)	$	124
Less: net income attributable to noncontrolling interests	(22)		(33)		(97)		(85)
Net (loss) income attributable to common stock	(29)		94		(2,096)		39
Adjustments:
Net income allocated to participating securities	—		(1)		—		(1)
Return from noncontrolling interest holders(a)	138		—		138		—
Net income (loss) available to common shares	109		93		(1,958)		38
Weighted-average common shares outstanding — basic	49.5		49.1		49.4		48.9
Basic EPS	$	2.20	$	1.89	$	(39.64)	$	0.78
Diluted EPS calculation
Net (loss) income	$	(7)	$	127	$	(1,999)	$	124
Less: net income attributable to noncontrolling interests	(22)		(33)		(97)		(85)
Net (loss) income attributable to common stock	(29)		94		(2,096)		39
Adjustments:
Net income allocated to participating securities	—		(1)		—		(1)
Return from noncontrolling interest holders(a)	138		—		138		—
Net income (loss) available to common shares	109		93		(1,958)		38
Weighted-average common shares outstanding — basic	49.5		49.1		49.4		48.9
Dilutive effect of potentially dilutive securities	—		0.1		—		0.3
Weighted-average common shares outstanding — diluted	49.5		49.2		49.4		49.2
Diluted EPS	$	2.20	$	1.89	$	(39.64)	$	0.77
Weighted-average anti-dilutive shares	3.3		3.2		4.4		2.3

(a)Return from noncontrolling interest holders relates to the deemed redemption of the noncontrolling interests in the Ares JV. For more information on the Ares JV and the Settlement Agreement, see Note 7 Joint Ventures.

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NOTE 11    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 nine months ended September 30, 2020 and 2019:

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

	Nine months ended September 30,
	2020				2019
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
	(in millions)
Service cost	$	1	$	3	$	1	$	3
Interest cost	1		3		2		3
Expected return on plan assets	(1)		—		(2)		—
Recognized actuarial loss	1		—		1		—
Settlement loss	—		—		1		—
Total	$	2	$	6	$	3	$	6

We did not make any significant contributions to our defined benefit pension plans for the three and nine months ended September 30, 2020. The Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted on March 27, 2020 and 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 nine months of 2020 until December 2020. We made contributions of $1 million and $2 million, respectively for the three months and nine months ended September 30, 2019. The post-retirement benefit cost associated with our August 2020 workforce reduction was not significant. The 2019 settlement loss, which was reclassified from accumulated other comprehensive income, was associated with early retirements and workforce reductions.

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NOTE 12    REVENUE RECOGNITION

We derive most of our revenue from sales of oil, natural gas and NGLs, with the remaining revenue 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 and nine months ended September 30, 2020 and 2019:

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
	(in millions)
Oil and natural gas sales:
Oil	$	246	$	457	$	795	$	1,433
Natural gas	34		50		98		155
NGLs	32		34		94		132
	312		541		987		1,720
Other revenue:
Electricity sales	43		38		75		88
Marketing and trading revenue	50		62		109		230
Other revenue	4		3		12		17
	97		103		196		335
Net derivative gain (loss) from commodity contracts	—		37		75		(31)
Total revenues	$	409	$	681	$	1,258	$	2,024

NOTE 13    LEASES

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

	Balance Sheet Location	September 30, 2020		December 31, 2019
		(in millions)		(in millions)
Right-of-use assets:
Operating lease, net	Other assets	$	43	$	59
Finance lease, net	PP&E	1		2
Total right-of-use assets		$	44	$	61
Lease liabilities:
Current
Operating lease	Accrued liabilities	$	10	$	27
Finance lease	Accrued liabilities	1		1
Long-term
Operating lease	Other long-term liabilities	31		37
Finance lease	Other long-term liabilities	—		1
Total lease liabilities		$	42	$	66

Our operating lease assets and liabilities decreased from year end 2019 primarily due to releasing five of our leased drilling rigs in the first quarter of 2020 in response to the industry downturn and economic environment. Our remaining two leased drilling rigs have been cold stacked and were included with our proved properties in our impairment assessment as discussed in Note 15 Asset Impairments. These right-of-use assets were not impaired.

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NOTE 14    INCOME TAXES

We estimate our annual effective income tax rate to record our quarterly provision in the jurisdictions in which we operate. Statutory tax rate changes and other significant or unusual items are 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 nine months ended September 30, 2020 and 2019, we did not provide any current or deferred tax provision or benefit. The difference between our statutory tax rate and our effective tax rate of zero for 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 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. The final regulations in the regulation package were published in the Federal Register on September 14, 2020 and are effective for tax years beginning on or after November 13, 2020. Although not yet effective, the publication of the final regulations clarified the amount of allowed addback for depreciation, depletion and amortization in the calculation of the limitation on the deduction of business interest expense. Based on our evaluation, these final regulations did not have a significant impact on our financial statements taken as a whole due to our full valuation allowance.

Certain of the transactions occurring upon our emergence from bankruptcy, and application of fresh start accounting, may have a material impact on our deferred tax balances, the full extent of which is currently unknown. Cancellation of debt income resulting from these transactions will primarily reduce our tax attributes, including but not limited to our net operating loss carryforwards, and our tax basis in property, plant and equipment. Further, as discussed in Note 1 Chapter 11 Proceedings, our pre-emergence common stock was cancelled and new common stock was issued on the Effective Date. This resulted in a change in ownership and, under IRC Section 382, may limit the deduction of our pre-emergence tax attributes, if any, and interest expense carryforwards. Additionally, we have incurred a significant amount of legal and professional fees related to the reorganization, a substantial portion of which may not be deductible for income tax purposes.

NOTE 15    ASSET IMPAIRMENTS

During the quarter ended March 31, 2020, we recorded a $1.7 billion impairment triggered by the sharp drop in commodity prices at the end of the first quarter of 2020 due to decreased 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 asset impairments as of our March 31, 2020 assessment date (in millions):

Proved oil and natural gas properties	$	1,487
Unproved properties	228
Other	21
Total	$	1,736

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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 then-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 located in the San Joaquin basin.

Unproved properties — In the first quarter of 2020, we determined our ability to develop our unproved properties was constrained for the foreseeable future.

NOTE 16    EQUITY

Chapter 11 Proceedings

On the Effective Date, as discussed in Note 1 Chapter 11 Proceedings, our pre-emergence authorized common and preferred stock were cancelled, pursuant to the Plan. Holders of our pre-emergence issued and outstanding common stock, including holders of contracts on our equity, did not receive any recovery.

Employee Stock Purchase Plan

On May 26, 2020, our then Board of Directors approved the termination of the California Resources Corporation 2014 Employee Stock Purchase Plan. No additional shares were issued under the plan after March 31, 2020.

Post-Emergence Equity

On the Effective Date, we issued an aggregate 83.3 million shares of new common stock, par value $0.01 per share, to the holders of allowed claims and ECR, as defined in the Plan. We reserved an aggregate 4.4 million shares of new common stock for future issuances in connection with the exercise of Warrants. In accordance with the Plan, our new common stock was issued as follows:

•17.3 million shares to Ares as partial consideration for its member interests in the Ares JV;

•27.1 million shares to our pre-petition creditor group in cancellation of their outstanding debt plus accrued interest up to the petition date;

•33 million shares in our Subscription Rights offering and 1.6 million shares to backstop parties in exchange for $446 million (net of a $4 million fee);

•3.5 million shares to backstop parties for the backstop commitment premium; and

•Approximately 821,000 shares for a Junior DIP Facility exit fee.

Before we emerged from the Chapter 11 Cases, our new common stock was approved for trading on the NYSE. On the Effective Date, we filed a Form 8-A to register the new common stock under Section 12(b) of the Exchange Act. Trading in the new common stock commenced on the NYSE on October 28, 2020 under the ticker "CRC".

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Warrants

As discussed in Note 1 Chapter 11 Proceedings, on the Effective Date, we reserved an aggregate 4.4 million shares for Warrants. The Tier 1 Warrants and Tier 2 Warrants are exercisable for 2% of the outstanding shares of new common stock and 3% of the outstanding new common stock (on a fully diluted basis calculated immediately after the Effective Date), respectively, both at an initial exercise price of $36 per share. The Warrants are exercisable from the Effective Date for a period of four years. The Warrant Agreement contains customary anti-dilution adjustments in the event of any stock split, reverse stock split, stock dividend, equity awards under a management incentive plan that our Board of Directors may establish pursuant to the Plan (if any) or other distributions. The warrant holder may elect, in its sole discretion, to pay cash or to exercise on a cashless basis, pursuant to which the holder will not be required to pay cash for shares of common stock upon exercise of the warrant but will instead receive fewer shares.

Unregistered Issuance of Equity Securities

Other than the shares issued in reliance of Section 4(a)(2) of the Securities Act as described below, we relied on Section 1145(a)(1) of the Bankruptcy Code as an exemption from the registration requirements of the Securities Act for the issuance of our new common stock and warrants. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under a plan of reorganization from registration under Section 5 of the Securities Act and state laws if three principal requirements are satisfied:

•The securities must be issued under a plan of reorganization by the debtor, its successor under a plan, or an affiliate participating in a joint plan of reorganization with the debtor;

•The recipients of the securities must hold a claim against, an interest in, or a claim for administrative expense in the case concerning the debtor or such affiliate; and

•The securities must be issued either (a) in exchange for the recipient’s claim against, interest in or claim for administrative expense in the case concerning the debtor or such affiliate or (b) principally in such exchange and partly for cash or property.

The (a) shares of new common stock issued pursuant to the Backstop Commitment Agreement, (b) shares of new common stock issued in connection with the payment of the backstop commitment premium and the exit fee for the Junior DIP Facility, and (c) Ares Settlement Stock issued to Ares pursuant to the Settlement Agreement were issued in each case without registration in reliance upon the exemption set forth in Section 4(a)(2) of the Securities Act and are therefore “restricted securities.”

On the Effective Date, we entered into a registration rights agreement with the backstop parties under the Backstop Commitment Agreement and each holder of at least 1% of the new common stock outstanding on the Effective Date, granting such parties customary registration rights with respect to their new common stock.

NOTE 17    CONDENSED COMBINED DEBTOR-IN-POSSESSION FINANCIAL INFORMATION

The financial statements below represent the unaudited condensed combined financial statements of the Debtors. Effective July 1, 2020, the results of the non-filing entities, which are comprised primarily of our consolidated joint ventures (see Note 7 Joint Ventures), are not included in these condensed combined financial statements. Intercompany transactions among the Debtors have been eliminated in the financial statements. Intercompany transactions among the Debtors and the non-Debtors have not been eliminated in these financial statements.

The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Debtors operated as independent entities.

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Condensed Consolidating Debtors' Balance Sheet
As of September 30, 2020
(in millions)
(DEBTOR-IN-POSSESSION: Entity Operating Under Chapter 11)
	September 30, 2020
Total current assets	$	379
Investments in subsidiaries	(261)
Total property, plant and equipment, net	3,937
Other assets	61
TOTAL ASSETS	$	4,116
Total current liabilities	1,217
Other long-term liabilities	724
Liabilities subject to compromise	4,516
Total equity	(2,341)
TOTAL LIABILITIES AND EQUITY	$	4,116

Condensed Consolidating Debtors' Statement of Operations
For the three months ended September 30, 2020
(in millions)
(DEBTOR-IN-POSSESSION: Entity Operating Under Chapter 11)
	Three months ended September 30, 2020
Total revenues	$	357
Total costs	436
Non-operating income	6
NET LOSS	$	(73)

Condensed Consolidating Debtors' Statement of Cash Flows
For the three months ended September 30, 2020
(in millions)
(DEBTOR-IN-POSSESSION: Entity Operating Under Chapter 11)
	Three months ended September 30, 2020
Net cash used in operating activities	$	(38)
Net cash used in investing activities	(1)
Net cash provided by financing activities	31
Decrease in cash	(8)
Cash—beginning of period	105
Cash—end of period	$	97

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

General

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.

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. 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 and on October 27, 2020 we emerged from the Chapter 11 proceedings as further described below.

Our condensed consolidated financial statements, including the Notes thereto, included in Part I, Item – Financial Statements have been prepared assuming we will continue as a going concern. We have applied Financial Accounting Standards Board Accounting Standards Codification 852, Reorganizations (ASC 852), in preparing these unaudited condensed consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the petition date (July 15, 2020), distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. As a result, we have segregated liabilities and obligations whose treatment and satisfaction are dependent on the outcome of the Chapter 11 Cases and classified these items as liabilities subject to compromise (LSTC) on our condensed consolidated balance sheet as of September 30, 2020. In addition, we have classified all income, expenses, gains or losses that were incurred or realized as a result of the Chapter 11 Cases subsequent to the petition date as reorganization items, net in our condensed consolidated statement of operations for the period ended September 30, 2020.

Further, we believe that we are required to adopt fresh start accounting upon emergence from bankruptcy because (1) the holders of existing voting shares prior to emergence received less than 50% of our new voting shares following our emergence from bankruptcy and (2) the reorganization value of our assets immediately prior to the confirmation of the Plan was less than the post-petition liabilities and allowed claims, which are included in liabilities subject to compromise. Fresh start accounting will be applied as of October 27, 2020, the date we emerged from bankruptcy. Under the principles of fresh start accounting, a new reporting entity is considered to have been created, and, as a result, the reorganization value of the emerging entity is assigned to individual assets and liabilities based on their estimated relative fair values. The process of estimating the fair value of our assets, liabilities and equity upon emergence is currently ongoing. In support of the Plan, the enterprise value of the successor company was estimated and approved by the Bankruptcy Court to be in the range of $2.2 billion to $2.8 billion. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements of the successor entity will not be comparable to the financial statements, including this statement, prepared prior to our Effective Date.

Chapter 11 Proceedings

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 retention of the vast majority of our receivables, our debt peaked at approximately $6.8 billion in May 2015. Since then, we have engaged in a series of asset sales, joint ventures, debt exchanges, tenders, debt repurchases and other financing transactions to reduce our overall level of debt and improve our balance sheet prior to filing for bankruptcy. As of September 30, 2020, we had outstanding net long-term debt of approximately $5.1 billion, of which $4.4 billion is presented as liabilities subject to compromise on our condensed consolidated balance sheet.

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code (Chapter 11 Cases) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court). The Chapter 11 Cases were jointly administered under the caption In re California Resources Corporation, et al., Case No. 20-33568 (DRJ). We filed with the Bankruptcy Court, on July 24, 2020, the Debtors’ Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code and, on October 8, 2020, the Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (as amended, supplemented or modified, the Plan). On October 13, 2020, the Bankruptcy Court confirmed the Plan, which was conditioned on certain items such as obtaining exit financing. The conditions to effectiveness of the Plan were satisfied and we emerged from Chapter 11 on October 27, 2020 (Effective Date).

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During the course of the Chapter 11 Cases, the Bankruptcy Court granted the relief requested in certain motions, 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, which allowed our business operations to continue uninterrupted during the pendency of the Chapter 11 Cases. All transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.

On July 15, 2020, immediately prior to the commencement of the Chapter 11 Cases, we and certain affiliates of Ares Management L.P. (Ares), including ECR Corporate Holdings L.P., a portfolio company of Ares (ECR), entered into a Settlement and Assumption Agreement (Settlement Agreement) related to our midstream joint venture, Elk Hills Power, LLC (Ares JV or Elk Hills Power), which holds our Elk Hills power plant and a cryogenic gas processing plant. On August 25, 2020, the Bankruptcy Court entered an order approving the Settlement Agreement on a final basis. Among other things, the Settlement Agreement included a conversion right, which would be deemed exercised upon our emergence from bankruptcy, allowing us to acquire all (but not less than all) of the equity interests in the Ares JV held by ECR in exchange for secured notes (EHP Notes), approximately 20.8% of our new common stock (Ares Settlement Stock) and $2.5 million in cash. For more information on the Settlement Agreement, see Part I, Item 1 – Financial Statements, Note 7 Joint Ventures.

The commencement of the Chapter 11 Cases constituted 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 New York 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 and together with the 5% Senior Notes due 2020 and 2021 Notes, the Senior 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 were stayed from taking any action against us, including exercising remedies as a result of any event of default. See Part I, Item 1 – Financial Statements, Note 6 Debt for additional details about our debt.

Joint Plan of Reorganization Under Chapter 11

Pursuant to the Plan, the following transactions occurred on the Effective Date:

•We issued an aggregate of 83.3 million shares of new common stock and reserved 4.4 million shares for issuance upon exercise of the warrants described below;

•We acquired all of the member interests in the Ares JV held by ECR in exchange for the EHP Notes, 17.3 million shares of new common stock and $2.5 million in cash (see Part I, Item 1 – Financial Statements, Note 6 Debt and Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information);

•Holders of secured claims under the 2017 Credit Agreement received 22.7 million shares of new common stock in exchange for those claims, and holders of deficiency claims under the 2017 Credit Agreement and all outstanding obligations under the 2016 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received 4.4 million shares of new common stock in exchange for those claims;

•In connection with the Subscription Rights offering and Backstop Commitment Agreement, 34.6 million shares of new common stock were issued in exchange for $446 million (net of a $4 million fee), the proceeds of which were used to pay down our debtor-in-possession financing;

•Our Subscription Rights offering was backstopped by certain creditors who received 3.5 million shares of new common stock as a backstop commitment premium (refer to Part I, Item 1 – Financial Statements, Note 16 Equity for additional information on the backstop commitment premium);

•The holders of Unsecured Debt Claims (as defined in the Plan) under the 2016 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received Tier 1 Warrants and Tier 2 Warrants (each as defined in the Plan and collectively, Warrants) to purchase up to 2% and 3%, respectively, of our outstanding shares (on a fully diluted basis calculated immediately after the Effective Date), with an initial exercise price of $36.00 per share, which expire on October 27, 2024 and have customary anti-dilution protections (refer to Note 16 Equity for additional information on the Warrants);

•All other general unsecured claims will be paid or disputed in the ordinary course of business; and

•All existing equity interests were cancelled and their holders received no distributions.

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As a condition to our emergence, we repaid the outstanding balance of our debtor-in-possession financing with proceeds from our Subscription Rights offering, Backstop Commitment Agreement and a new senior secured revolving credit facility led by Citibank, N.A. We also issued approximately 821,000 shares of new common stock for a junior debtor-in-possession exit fee. For more information on our debtor-in-possession credit agreements and our post-emergence indebtedness, see Part I, Item 1 – Financial Statements, Note 6 Debt.

Additionally, pursuant to our Plan, our post-emergence Board of Directors consists of nine directors as follows: (i) our President and Chief Executive Officer, Todd A. Stevens, (ii) seven non-employee directors, including Douglas E. Brooks, Tiffany (TJ) Thom Cepak, James N. Chapman, Mark A. McFarland, Julio M. Quintana, William B. Roby and Brian Steck, and (iii) one vacancy which will be filled by our post-emergence Board of Directors in accordance with our charter and bylaws. The seven non-employee directors were all appointed to the Board of Directors on October 27, 2020.

Our Board of Directors has determined that Ms. Cepak and Messrs. Brooks, Chapman, McFarland, Quintana, Roby and Steck are independent directors as that term is defined in the listing standards of the New York Stock Exchange (NYSE). Mr. Stevens is not considered by our Board of Directors to be independent because of his current employment with CRC.

Changes to our Stock-Based Compensation Programs

As a result of our bankruptcy, the outstanding stock-based awards under our Amended and Restated California Resources Corporation Long-Term Incentive Plan were cancelled on our Effective Date. Any new stock-based awards or compensation plans will be reviewed and approved by our Board of Directors, which includes seven new directors appointed on October 27, 2020.

The cancellation of these stock-based compensation awards resulted in the recognition of all previously unrecognized compensation expense for equity-settled awards and the liability related to our cash-settled awards was eliminated as the participants received no consideration. The net effect of these adjustments was not material to our financial statements.

Changes to the 2020 Compensation Programs in Second Quarter 2020

In the second quarter of 2020, resulting from the unprecedented circumstances affecting the industry and market volatility, we reviewed our incentive programs for the entire workforce to determine whether those programs appropriately aligned compensation opportunities with our 2020 goals and ensured the stability of our workforce. Following this review, effective May 19, 2020, our then Board of Directors approved changes in the variable compensation programs for all participating employees. The previously established target amounts of 2020 variable compensation programs did not change; however, all amounts that vest are being settled in cash. 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. At that time, there were no changes to stock-based compensation awards granted prior to February 2020; however, these pre-2020 awards were subsequently cancelled as part of the Plan. Changes to the variable compensation programs had 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 remained largely the same as the amounts that would have been paid at target prior to the changes. Our future compensation programs will be determined by our new Board of Directors.

Organizational Changes

During the course of the Chapter 11 Cases, we evaluated the structure of our workforce and, in August 2020, we implemented organizational changes that resulted in a reduction of our headcount from 1,250 to approximately 1,100 employees. We believe the steps taken improved and strengthened our business as we emerge from bankruptcy. We recorded a one-time $10 million restructuring charge in the third quarter of 2020. We will continue to evaluate resource levels depending on commodity prices.

Business Environment and Industry Outlook

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Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and gas prices and differentials may fluctuate significantly as a result of numerous market-related variables, especially given current global geopolitical and economic conditions. These and other factors make it impossible to predict realized prices reliably.

Prices for oil and gas products in 2020 have been strongly influenced by the Coronavirus Disease 2019 (COVID-19) pandemic and by the actions of foreign producers. The COVID-19 pandemic caused an unprecedented demand collapse due to global shelter-in-place orders, travel restrictions and general economic uncertainty, which negatively impacted crude oil prices. In addition, members of the Organization of the Petroleum Exporting Countries (OPEC) and Russia agreed to carry out record oil production cuts in April 2020 to be followed by gradual incremental increases in multiple steps. In the summer of 2020, OPEC and Russia moved ahead with the first hike in crude oil output. The next hike in crude oil output is currently scheduled for January 2021. As a result of these conditions, the Brent oil price has been trading in a narrow range around $40 per barrel for several months.

Reduced demand initially 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 declined precipitously, temporarily reaching negative values for spot West Texas Intermediate (WTI) crude. From May 2020 through August 2020, oil prices began to recover as inventory levels stabilized and an easing of shelter-in-place restrictions created partial demand recovery. Prices declined again slightly in September 2020 as demand for oil dropped due to an increase in COVID-19 cases around the world. Demand and pricing may decline again due to a resurgence in the number of cases globally and across parts of the United States, which could result in the re-imposition of certain restrictions. The current futures forward curve for Brent crude indicates that prices may continue at close to current levels, which are significantly 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 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, a resurgence 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 1A – Risk Factors, below for further discussion regarding the impact of the pandemic and declines in commodity prices.

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

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
Brent oil ($/Bbl)	$	43.37	$	62.00	$	42.53	$	64.74
WTI oil ($/Bbl)	$	40.93	$	56.45	$	38.32	$	57.06
NYMEX gas ($/MMBtu)	$	1.93	$	2.27	$	1.92	$	2.72

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

Operations

Response to COVID-19 Pandemic and Industry Downturn

We have taken several steps and continue to actively work to mitigate the effects of the COVID-19 pandemic and the industry downturn on our operations, financial condition and liquidity.

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In response to the rapid fall in commodity prices in March 2020, 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 $7 million in the second and third quarters of 2020. We also monetized all of our crude oil hedges in March 2020, except for certain hedges held by our joint venture with Benefit Street Partners (BSP JV), for approximately $63 million to enhance our liquidity. We began shutting in high cost, negative margin wells in March 2020 to reduce operating costs and enhance cash flow which curtailed average net production volumes by approximately 5 MBoe/d and 3 MBoe/d for the second and third quarters of 2020, respectively. 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 third quarter 2020 average operating expense run rate is below $50 million per month compared to the first quarter of 2020 average of $64 million per month. At our current level of capital investment and surface activity levels, production could 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 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, in April 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. In August 2020, we implemented organizational and operational efficiencies that resulted in a reduction of our headcount to approximately 1,100 employees. These actions were made in an effort to preserve liquidity after the 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. Accordingly, they worked through the shutdowns 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

We conduct our operations on properties that we hold through fee interests, mineral leases and other contractual arrangements. We are the largest non-governmental oil and natural gas mineral acreage holder in California, with interests in 2.1 million net mineral acres, approximately 60% of which is held in fee and 17% is held by production. Our oil and gas leases have primary terms ranging from one to ten years. Once production commences, the leases are typically extended on the producing acreage through the end of their producing life. As a result of our large mineral acre position held in fee, we generally have the flexibility to shut-in wells while retaining our oil and gas leases which are held by production.

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.

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 carbon capture and sequestration, renewable energy opportunities, agricultural activities and other commercial uses.

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Our share of production and reserves from operations in the Wilmington field 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 costs. We record a share of production and reserves to recover a portion of such capital and production costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and production 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 costs. However, our net economic benefit is greater when product prices are higher. These contracts represented approximately 17% of our net production for the three months ended September 30, 2020.

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 revenue, general and administrative and operating costs and has no effect on our net results.

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

Crude Oil — We sell nearly 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. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.

California is heavily reliant on imported sources of energy, with approximately 72% 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 basis at market-based 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 producing areas. Transportation capacity influences prices because California imports approximately 90% of its natural gas from other states and Canada. As a result, we typically enjoy favorable 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 of our revenue is from natural gas.

In addition to selling natural gas, we also use natural gas for our steamfloods and power generation. As a result, 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. Conversely, lower natural gas prices lower the 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 of our natural gas production under individually negotiated contracts using market-based pricing on a monthly or shorter basis.

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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 volatility.

Our earnings are also affected by the performance of our complementary processing and power-generation assets. 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 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. 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 of $20 million in April 2020 when the contract expired. We sell virtually all of our NGLs using index-based pricing. Our NGLs are generally sold pursuant to contracts that are renewed annually. Approximately 33% 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 operating costs and increases reliability. We sell the excess electricity generated to a local utility, other third parties and the grid. The power sold to the utility is subject to agreements through the end of 2023, which include 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 grid. The prices obtained for excess power impact our earnings but generally by an insignificant amount.

Derivatives and Hedging Activities

We opportunistically seek strategic hedging transactions to help protect our cash flow, operating margin and capital program from both the cyclical nature 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.

The Senior DIP Credit Agreement required 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 to satisfy this requirement. Our post-emergence Revolving Credit Facility and Second Lien Term Loan require us to maintain hedges on a higher amount of crude oil production as described in Part I, Item 1 – Financial Statements, Note 6 Debt.

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 September 30, 2020 by our development joint venture partners, before transaction costs:

	Cumulative Investment through
	September 30, 2020
	(in millions)
Alpine	$	227
Royale	17
MIRA	139
BSP	200
Total Capital Investment	$	583

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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

In July 2019, we entered into a development agreement with Alpine Energy Capital, LLC (Alpine). Alpine has committed to invest $320 million, which may be increased to 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.

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 may be lifted by mutual consent. As of September 30, 2020, funding for the initial development phase has not re-started.

Midstream Joint Venture

Ares JV

In February 2018, our wholly-owned subsidiary California Resources Elk Hills, LLC (CREH) entered into a midstream JV 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. On the Effective Date, as required by the Note Purchase Agreement, CREH transferred its ownership of two low temperature separation plants located at the Elk Hills field to Elk Hills Power.

Prior to our Effective Date, we held 50% of the Class A common interest and 95.25% of the Class C common interest in the Ares JV. 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. The Ares JV was 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 purchased electricity 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 were 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 served as the operator of the Ares JV and provided operational and support services in exchange for a monthly fee pursuant to a Master Services Agreement. These agreements became intercompany agreements on the Effective Date and were cancelled as described below.

As described above in Business Environment and Outlook and Part I, Item 1 – Financial Statements, Note 1 Chapter 11 Proceedings, we entered into the Settlement Agreement with ECR and Ares which, among other things, changed the liquidation preference for the Class B member interest to $835 million, decreased the preferred return from 13.5% per annum to 9.5% per annum payable at the end of each month, removed the liquidation premium for the Class A common interest and removed the payment of any previously accrued but unpaid preferred distributions plus a make-whole payment that ECR, as the holder of the Class B preferred interests, would otherwise have been entitled to in the event of a redemption transaction. The Settlement Agreement granted us the right (Conversion Right) to acquire all (but not less than all) of the equity interests of Elk Hills Power owned by ECR in exchange for the EHP Notes, Ares Settlement Stock and $2.5 million in cash. The Conversion right was deemed to have been exercised on the Effective Date.

Although certain provisions in the Settlement Agreement were not effective until certain conditions were met, such as the Bankruptcy Court entering a final order, we determined that the amended terms were substantively different such that the existing Class A common, Class B preferred and Class C common member interests held by ECR were treated as redeemed in exchange for new member interests issued at fair value. The estimated fair value of the new member interests was lower than the carrying value of the existing member interests by $138 million. In accordance with GAAP, the return from noncontrolling interest holders was recorded to additional paid-in capital on our condensed consolidated balance sheet as of September 30, 2020. However as required by GAAP, the return is included in our earnings per share calculations. See Part I, Item 1 – Financial Statements, Note 10 Earnings per Share for adjustments to net income (loss) attributable to common stock which include a return from noncontrolling interests.

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We were deemed to have exercised the Conversion Right on the Effective Date and we issued the EHP Notes in the aggregate principal amount of $300 million, Ares Settlement Stock comprising approximately 20.8% (subject to dilution) of the new common stock (Conversion) and $2.5 million in cash. Upon the Conversion, Elk Hills Power became an indirect wholly-owned subsidiary, and Ares and its affiliates ceased to have any direct or indirect interest in Elk Hills Power, other than any interest Ares may have indirectly through its interests in the EHP Notes and Ares Settlement Stock. In connection with the Conversion, Elk Hills Power’s limited liability company agreement was amended and restated.

In connection with the Conversion, on the Effective Date, we entered into a Sponsor Support Agreement dated the Effective Date (Support Agreement) pursuant to which, among other things, the parties agreed that Elk Hills Power will be our primary provider of electricity to, and will be the primary processor of our natural gas produced from, the Elk Hills field, which is already consistent with our current practice.

On the Effective Date, in connection with the Conversion, we terminated: (a) the Commercial Agreement, dated as of February 7, 2018, by and between Elk Hills Power and CREH and (b) the Master Services Agreement, dated as of February 7, 2018, by and between Elk Hills Power and CREH.

For more information on the Ares JV, see Part I, Item 1 – Financial Statements, Note 7 Joint Ventures. For more information on the Settlement Agreement, see Part I, Item 1 – Financial Statements, Note 1 Chapter 11 Proceedings.

Fixed and Variable Costs

Our production 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 measures taken to address the recent industry downturn, we have demonstrated that we can significantly reduce our operating costs in response to prevailing market conditions. As a result, we continue to believe that a significant portion of our operating costs are variable over the lifecycle of our fields. We actively manage our fields to optimize production and minimize costs. When we see growth in a field, we increase capacities and, similarly, when a field nears the end of its economic life, we manage the costs while it remains economically viable to produce.

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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 nine months ended September 30, 2020 and 2019:

	Three months ended September 30,		Nine months ended September 30,
	2020	2019	2020	2019
Oil (MBbl/d)
San Joaquin Basin	40	51	42	53
Los Angeles Basin	22	24	25	24
Ventura Basin	2	4	3	4
Total	64	79	70	81
NGLs (MBbl/d)
San Joaquin Basin	14	16	14	15
Ventura Basin	—	—	—	1
Total	14	16	14	16
Natural gas (MMcf/d)
San Joaquin Basin	142	162	148	163
Los Angeles Basin	2	2	2	2
Ventura Basin	4	4	4	6
Sacramento Basin	20	28	21	29
Total	168	196	175	200
Total Net Production (MBoe/d)	106	128	113	130

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 September 30, 2020 compared to the same period in 2019, total daily production decreased by approximately 22 MBoe/d or 17%. The decrease in production related to higher downtime caused by significantly reduced well repair work, as well as the temporary shut-in of certain wells beginning in March 2020, which negatively impacted our net production for the three months ended September 30, 2020 by 3 MBoe/d compared to the same prior-year period. Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the third quarter of 2020 by approximately 1 MBoe/d compared to the same period in 2019. Excluding the effects of shut-in production and PSC-type contracts, our base decline was still in line with our previously disclosed rate of low to mid-teens, which largely resulted from low internal capital investment and well repair work.

For the nine months ended September 30, 2020 compared to the same period in 2019, total daily production decreased by approximately 17 MBoe/d or 13%. The decrease in production related to higher downtime caused by significantly reduced well repair work, as well as the temporary shut-in of certain wells beginning in March 2020, and the effect of the May 2019 partial divestiture of the Lost Hills field, which negatively impacted our net production for the nine months ended September 30, 2020 by 3 MBoe/d compared to the same prior-year period. Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the nine months of 2020 by 3 MBoe/d compared to the same period in 2019. Excluding the effects of the Lost Hills transaction, shut-in production and PSC-type contracts, our base decline was still in line with our previously disclosed rate of low to mid-teens, which largely resulted from low internal capital investment and well repair work.

With an ongoing gradual increase of well repair work, we believe our base decline rate going forward will gradually return to the low to mid-teens.

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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 nine months ended September 30, 2020 and 2019:

	Three months ended September 30,
	2020			2019
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	43.37		$	62.00
Realized price without hedge	$	41.83	96%	$	62.85	101%
Settled hedges	0.32			5.56
Realized price with hedge	$	42.15	97%	$	68.41	110%
WTI	$	40.93		$	56.45
Realized price without hedge	$	41.83	102%	$	62.85	111%
Realized price with hedge	$	42.15	103%	$	68.41	121%
NGLs ($ per Bbl)
Realized price (% of Brent)	$	25.16	58%	$	23.55	38%
Realized price (% of WTI)	$	25.16	61%	$	23.55	42%
Natural gas
NYMEX ($/MMBtu)	$	1.93		$	2.27
Realized price without hedge ($/Mcf)	$	2.22	115%	$	2.73	120%
Settled hedges	0.02			(0.01)
Realized price with hedge ($/Mcf)	$	2.24	116%	$	2.72	120%

	Nine months ended September 30,
	2020			2019
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	42.53		$	64.74
Realized price without hedge	$	41.27	97%	$	65.03	100%
Settled hedges	2.00			3.13
Realized price with hedge	$	43.27	102%	$	68.16	105%
WTI	$	38.32		$	57.06
Realized price without hedge	$	41.27	108%	$	65.03	114%
Realized price with hedge	$	43.27	113%	$	68.16	119%
NGLs ($ per Bbl)
Realized price (% of Brent)	$	25.17	59%	$	31.04	48%
Realized price (% of WTI)	$	25.17	66%	$	31.04	54%
Natural gas
NYMEX ($/MMBtu)	$	1.92		$	2.72
Realized price without hedge ($/Mcf)	$	2.05	107%	$	2.82	104%
Settled hedges	0.06			(0.01)
Realized price with hedge ($/Mcf)	$	2.11	110%	$	2.81	103%

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Oil — Brent index and realized prices were lower in both the three and nine months ended September 30, 2020 compared to the same prior-year periods due to the combination of the supply increase caused by the Saudi-Russia price war and the severe demand decline caused by COVID-19. Prices collapsed in March 2020 and gradually improved to around the current levels in June 2020 as a result of the significant production curtailments OPEC and other nations implemented in response to COVID-19.

NGLs — Prices for NGLs increased slightly for the three months ended September 30, 2020 compared to the same period in 2019 due to improvements in negotiated sales differentials along with stronger NGL values relative to crude. NGL prices declined for the nine months ended September 30, 2020 compared to the same prior-year period as steady U.S. production exceeded the COVID-19 related decline in demand, causing lower domestic NGL prices. We continued to receive premium prices for NGLs relative to national hub prices.

Natural Gas — Our natural gas realized prices were lower in both the three and nine months ended September 30, 2020 than the comparable periods of 2019. The decrease was due to increased nationwide natural gas production and higher inventories across the U.S. primarily due to lower demand resulting from the 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. Prices began to increase in September 2020 anticipating lower future production as a result of reduced capital investment by producers.

Balance Sheet Analysis

Balance sheet accounts and changes in these accounts, as of September 30, 2020 and December 31, 2019, are discussed below:

	September 30,		December 31,
(Debtor-in-Possession: Entity Operating Under Chapter 11)	2020		2019
	(in millions)
Cash	$	122	$	17
Trade receivables	$	155	$	277
Inventories	$	61	$	67
Other current assets, net	$	82	$	130
Property, plant and equipment, net	$	4,360	$	6,352
Other assets	$	76	$	115
Current portion of long-term debt	$	—	$	100
Debtor-in-possession financing	$	733	$	—
Accounts payable	$	221	$	296
Accrued liabilities	$	240	$	313
Long-term debt	$	—	$	4,877
Deferred gain and issuance costs, net	$	—	$	146
Other long-term liabilities	$	727	$	720
Liabilities subject to compromise	$	4,516	$	—
Mezzanine equity	$	692	$	802
Equity attributable to common stock	$	(2,341)	$	(389)
Equity attributable to noncontrolling interests	$	68	$	93

Cash — Cash at September 30, 2020 and December 31, 2019 included restricted cash of $24 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 September 2020 compared to December 2019.

Other current assets, net — The decrease in other current assets, net was primarily due to collections from our joint interest partners, an impairment in March 2020 of unrecovered capital investments and a decrease in the fair value of the current portion of our derivative contracts. The decrease in fair value of our derivative contracts primarily related to a lower percentage of our oil production hedged between comparative periods.

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Property, plant and equipment, net — The decrease in property, plant and equipment, net primarily resulted from an impairment of certain proved and unproved properties recorded in the first quarter of 2020, depreciation, depletion, and amortization (DD&A) and sales of certain royalty interests and non-core assets in January 2020. For further detail about our asset impairment, see Part I, Item 1 – Financial Statements, Note 15 Asset Impairments.

Other assets — Other assets decreased primarily due to the utilization of parts for a scheduled turnaround at our Elk Hills power plant as well as a decrease in operating lease assets due to releasing drilling rigs, both of which occurred in the first quarter of 2020.

Current portion of long-term debt — Current maturities of long-term debt decreased by $100 million reflecting

the payoff of our 2020 Senior Notes in January 2020.

Debtor-in-possession financing — As a result of our Chapter 11 Cases, we obtained debtor-in-possession financing to allow us to continue operating our business during the pendency of the bankruptcy proceedings. Proceeds from the debtor-in-possession financing were used to pay off our 2014 Revolving Credit Facility. See Part I, Item 1 – Financial Statements, Note 6 Debt for additional information on our debtor-in-possession credit agreements.

Accounts payable — The amount due to our vendors decreased as a result of our reduced capital program and lower activity levels in the third quarter of 2020 as compared to the fourth quarter of 2019.

Accrued liabilities — The decrease in accrued liabilities primarily related to bonus payments made to employees in the first quarter of 2020, releasing drilling rigs, and lower drilling and completion activity related to the Alpine JV due to the suspension of further capital funding as a result of low commodity prices. These decreases were partially offset by accrued legal, professional and other fees related to our Chapter 11 Cases and an increase in our liability for property taxes due to the timing of payments. As of September 30, 2020, accrued interest on our long-term debt impaired by our Chapter 11 Cases was presented as LSTC on our condensed combined balance sheet. See Part I, Item 1 – Financial Statements, Note 2 Basis of Presentation for additional information about liabilities subject to compromise.

Long-term debt — The decrease in long-term debt related to the reclassification of long-term debt to LSTC on our condensed combined balance sheet as of September 30, 2020. See Part I, Item 1 – Financial Statements, Note 2 Basis of Presentation for additional information.

Deferred gain and issuance costs, net — The decrease in deferred gain and issuance costs, net resulted from the elimination of unamortized amounts associated with our pre-petition long-term debt as a result of Chapter 11 Cases.

Liabilities subject to compromise — The increase resulted from the reclassification of our long-term debt along with related accrued interest as of the petition date as liabilities subject to compromise on our condensed consolidated balance sheet as of September 30, 2020.

Mezzanine equity — The decrease in mezzanine equity primarily resulted from the deemed redemption of the equity interests in our Ares JV held by ECR for less than their carrying amount. See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures and Development Joint Ventures above for additional information on the Settlement Agreement and the Ares JV.

Equity attributable to common stock — Equity attributable to common stock decreased primarily as a result of the net loss in the nine months ended September 30, 2020.

Equity attributable to noncontrolling interests — Equity attributable to noncontrolling interests includes BSP's preferred interest in the BSP JV. The decrease primarily related to distributions to our joint venture partner.

46

Statements of Operations Analysis

Results of Oil and Gas Operations

The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses, on a per Boe basis for the three and nine months ended September 30, 2020 and 2019:

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
Production costs	$	14.52	$	18.82	$	14.85	$	19.32
Production costs, excluding effects of PSC-type contracts(a)	$	13.37	$	17.44	$	14.03	$	17.82
Field general and administrative expenses(b)	$	1.34	$	1.19	$	1.16	$	1.24
Field depreciation, depletion and amortization(b)	$	8.03	$	9.28	$	8.68	$	9.38
Field taxes other than on income(b)	$	3.40	$	2.73	$	3.10	$	2.60

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

(b)Excludes corporate expenses.

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Consolidated Results of Operations

The following table presents our consolidated results of operations and key financial measures for the three and nine months ended September 30, 2020 and 2019:

	Three months ended September 30,						Nine months ended September 30,
	2020			2019			2020			2019
	(in millions)
Oil and natural gas sales	$	312		$	541		$	987		$	1,720
Net derivative gain (loss) from commodity contracts	—			37			75			(31)
Marketing and trading revenue	50			62			109			230
Electricity sales	43			38			75			88
Other revenue	4			3			12			17
Production costs	(141)			(221)			(460)			(684)
General and administrative expenses	(64)			(66)			(193)			(228)
Depreciation, depletion and amortization	(89)			(118)			(296)			(357)
Asset impairments	—			—			(1,736)			—
Taxes other than on income	(42)			(42)			(121)			(119)
Exploration expense	(2)			(5)			(9)			(25)
Marketing and trading costs	(35)			(45)			(67)			(170)
Electricity cost of sales	(17)			(18)			(47)			(51)
Transportation costs	(10)			(10)			(31)			(30)
Other expenses, net	(22)			(8)			(75)			(33)
Reorganization items, net	66			—			66			—
Interest and debt expense, net	(28)			(95)			(200)			(293)
Net gain on early extinguishment of debt	—			82			5			108
Other non-operating expenses	(32)			(8)			(93)			(18)
(Loss) income before income taxes	(7)			127			(1,999)			124
Income tax	—			—			—			—
Net (loss) income	(7)			127			(1,999)			124
Net income attributable to noncontrolling interests	(22)			(33)			(97)			(85)
Net (loss) income attributable to common stock	$	(29)		$	94		$	(2,096)		$	39
Adjusted net (loss) income(a)	$	(55)		$	17		$	(265)		$	34
Adjusted EBITDAX(a)	$	103		$	278		$	373		$	834
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.

Stock-Based Compensation

Our consolidated results of operations for the three and nine months ended September 30, 2020 and 2019 include the effects of long-term stock-based compensation plans under which awards are granted annually to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our pre-emergence equity-settled awards granted to executives included stock options, restricted stock units and performance stock units that either cliff vested at the end of a three-year period or vested ratably over a three-year period, some of which are partially settled in cash. Our pre-emergence equity-settled awards granted to non-employee directors included stock grants that vested immediately or restricted stock units that cliff vested after one year. Our cash-settled awards granted to non-executive employees vested ratably over a three-year period. Unvested awards granted to employees and non-employee directors were cancelled at the Effective Date pursuant to the Plan.

48

Changes in our stock price introduce volatility in our results of operations because we pay cash-settled awards based on our stock price on the vesting date and accounting rules require that we adjust our obligation for unvested awards to the amount that would be paid using our stock price at the end of each reporting period. Cash-settled awards, including executive awards partially settled in cash, accounted for approximately 40% of our total outstanding awards at September 30, 2020. Our obligations for equity-settled awards are not similarly adjusted for changes in our stock price.

Three months ended September 30, 2020 vs. 2019

Oil and natural gas sales — Oil and natural gas sales decreased 42%, or $229 million, for the three months ended September 30, 2020 compared to the same period of 2019 due to lower realized prices and production as reflected in the following table:

	Oil		NGLs		Natural Gas		Total
	(in millions)
Three months ended September 30, 2019	$	457	$	34	$	50	$	541
Changes in realized prices	(153)		2		(12)		(163)
Changes in production	(58)		(4)		(4)		(66)
Three months ended September 30, 2020	$	246	$	32	$	34	$	312

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 settled hedges were $2 million for the three months ended September 30, 2020 compared to net proceeds of $40 million for the same period of 2019. Including the effect of settled hedges, our oil and natural gas revenue decreased by $424 million or 51% compared to the same prior-year period.

Net derivative gain (loss) from commodity contracts — We did not have a net derivative gain or loss from commodity contracts for the three months ended September 30, 2020 compared to a gain of $37 million in the same period of 2019. Non-cash changes in the fair value of our outstanding derivatives resulted from the positions held at the end of each period as well as the relationship between contract prices, volatility, time to expiration and the associated forward curves.

	Three months ended September 30,
	2020		2019
	(in millions)
Non-cash derivative gain (loss), excluding noncontrolling interest	$	4	$	(6)
Non-cash derivative (loss) gain, noncontrolling interest	(6)		3
Total non-cash changes	(2)		(3)
Net proceeds on settled commodity derivatives	2		40
Net derivative gain from commodity contracts	$	—	$	37

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Production costs — Production costs for the three months ended September 30, 2020 decreased $80 million to $141 million compared to $221 million for the same period of 2019, resulting in a 36% decrease. Excluding employee incentive compensation, our production costs decreased $83 million to $134 million for the three months ended September 30, 2020 from $217 million during the same prior-year period. The decrease was primarily attributable to efficiencies and streamlining of our operations along with workforce reductions. Also contributing to the decrease were lower operating costs due to shut-in wells, as well as reduced activity levels, such as downhole maintenance, in response to the current economic environment.

	Three months ended September 30,
	2020		2019
	(in millions)
Production costs	$	141	$	221
Exclude: Stock-based compensation	—		1
Exclude: Other employee incentive awards	(7)		(5)
Production costs, excluding employee incentive compensation	$	134	$	217

General and administrative expenses — Our general and administrative (G&A) expenses were $64 million for the three months ended September 30, 2020 compared to $66 million for the three months ended September 30, 2019. Excluding employee incentive compensation and severance, our G&A expenses decreased $11 million to $44 million for the three months ended September 30, 2020 from $55 million for the same prior-year period. The decrease in G&A expenses, excluding employee incentive compensation and severance, resulted from our ongoing cost saving efforts, our August 2020 workforce reduction and a decline in spending across a number of cost categories. These savings were partially offset by obtaining additional insurance as a result of our Chapter 11 Cases.

The $10 million increase in other employee incentive awards for the three months ended September 30, 2020 from the same period in 2019 was primarily the result of changes to the variable portion of our incentive compensation program in May 2020, which was approved by the Bankruptcy Court, and a higher payout approved on pre-established performance metrics. For additional information on the variable compensation program, see Part I, Item 1 – Financial Statements, Note 1 Chapter 11 Proceedings and General above.

	Three months ended September 30,
	2020		2019
	(in millions)
G&A expenses	$	64	$	66
Exclude: Stock-based compensation	(1)		(1)
Exclude: Other employee incentive awards	(19)		(9)
Exclude: Severance	—		(1)
G&A expenses, excluding employee incentive compensation and severance	$	44	$	55

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $29 million to $89 million in the third quarter of 2020 compared to $118 million in 2019 was predominately due to a decrease in our depletable basis as a result of our asset impairment recorded in March 2020. For further detail about our asset impairment, see Part I, Item 1 – Financial Statements, Note 15 Asset Impairments.

Reorganization items, net — We recognized a $66 million net gain in the third quarter of 2020 primarily due to the write-off of the unamortized balance of our deferred gain, original issue discounts and deferred issuance costs on our long-term debt partially offset by increased legal, professional and other fees, including debtor-in-possession financing costs, all of which related to our bankruptcy proceedings. See Part I, Item 1 – Financial Statements, Note 2 Basis of Presentation for additional information about reorganization items, net.

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Interest and debt expense, net — Interest and debt expense, net decreased $67 million to $28 million in the third quarter of 2020 compared to $95 million in the same period of 2019 primarily due to suspending the accrual of interest on our pre-petition long-term debt obligations as of the petition date, a lower overall debt balance primarily resulting from repayment of our 2020 Senior Notes in January 2020 and repurchases of our Second Lien Notes in 2019, and lower variable interest rates on borrowings under our 2016 Credit Agreement and 2017 Credit Agreement. The decrease was partially offset by interest on our debtor-in-possession financing. See Part I, Item 1 – Financial Statements, Note 6 Debt for additional information on our debtor-in-possession financing.

Net gain on early extinguishment of debt — We did not repurchase any debt during the three months ended September 30, 2020, compared to recognizing a debt extinguishment gain of $82 million in the same period of 2019 related to repurchases of our Second Lien Notes.

Other non-operating expense — Other non-operating expense increased $24 million to $32 million for the three months ended September 30, 2020 compared to $8 million in the same period for 2019. The increase was primarily a result of legal, professional and other fees associated with the preparation of the Chapter 11 Cases, incurred prior to our petition date, as well as a one-time severance charge related to our August 2020 workforce reduction.

Net income attributable to noncontrolling interests — The decrease of $11 million in net income attributable to noncontrolling interests to $22 million for the quarter ended September 30, 2020 from $33 million for the same period in 2019 was primarily related to lower revenue from the net profits interest held by the BSP JV and changes in derivative gain (loss) due to a decline in commodity prices between periods. See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information.

Nine months ended September 30, 2020 vs 2019

Oil and natural gas sales — Oil and natural gas sales decreased 43%, or $733 million, for the nine months ended September 30, 2020 compared to the same period of 2019 due to lower realized prices and production as reflected in the following table:

	Oil		NGLs		Natural Gas		Total
	(in millions)
Nine months ended September 30, 2019	$	1,433	$	132	$	155	$	1,720
Changes in realized prices	(525)		(24)		(43)		(592)
Changes in production	(113)		(14)		(14)		(141)
Nine months ended September 30, 2020	$	795	$	94	$	98	$	987

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 settled hedges were $42 million for the nine months ended September 30, 2020, excluding the effect of our derivative contracts sold prior to maturity in the first quarter of 2020, compared to net proceeds of $68 million for the same period of 2019, which had a negative impact of $26 million on our total revenue between periods. Including the effect of settled hedges and proceeds from derivative contracts sold in the first quarter of 2020, our oil and natural gas revenue decreased by $696 million or 39% compared to the same prior-year period.

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Net derivative gain (loss) from commodity contracts — Net derivative gain from commodity contracts was $75 million for the nine months ended September 30, 2020 compared to a loss of $31 million in the same period of 2019, representing an overall change of $106 million as reflected in the following table. Non-cash changes in the fair value of our outstanding derivatives resulted from the positions held at the end of each period as well as the relationship between contract prices, volatility, time to expiration and the associated forward curves.

	Nine months ended September 30,
	2020		2019
	(in millions)
Non-cash derivative loss, excluding noncontrolling interest	$	(31)	$	(99)
Non-cash derivative gain, noncontrolling interest	1		—
Total non-cash changes	(30)		(99)
Net proceeds on settled commodity derivatives	42		68
Net proceeds on derivative sales prior to maturity	63		—
Net derivative gain (loss)	$	75	$	(31)

Marketing and trading revenue — The decrease in marketing and trading revenue of $121 million to $109 million for the nine months ended September 30, 2020 compared to $230 million in the same period of 2019 was due to lower volumes related to our natural gas trading activities.

Production costs — Production costs for the nine months ended September 30, 2020 decreased $224 million to $460 million compared to $684 million for the same period of 2019, resulting in a 33% decrease. Excluding employee incentive compensation, our production costs decreased $216 million to $443 million for the nine months ended September 30, 2020 from $659 million during the same prior-year period. The decrease was primarily attributable to efficiencies and streamlining of our operations, along with our workforce reductions and reduced work schedules during the months of April and May 2020. The operating costs of shut-in wells, as well as lower activity levels in response to the current environment, such as downhole maintenance, also contributed to the decrease.

	Nine months ended September 30,
	2020		2019
	(in millions)
Production costs	$	460	$	684
Exclude: Stock-based compensation	—		(7)
Exclude: Other employee incentive awards	(17)		(18)
Production costs, excluding employee incentive compensation	$	443	$	659

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General and administrative expenses — Our G&A expenses were $193 million for the nine months ended September 30, 2020 and decreased $35 million from $228 million for the nine months ended September 30, 2019. Excluding employee incentive compensation and severance, our G&A expenses decreased $27 million to $148 million for the nine months ended September 30, 2020 from $175 million for the same prior-year period. The decrease in G&A expenses, excluding employee incentive compensation, resulted from cost saving efforts, workforce reductions, reduced work hours in April and May 2020 and a decline in spending across a number of cost categories. These savings were partially offset by the cost of obtaining additional insurance due to our Chapter 11 Cases and lower cost capitalization as a result of temporarily suspending our capital program.

The $12 million increase in other employee incentive awards for the nine months ended September 30, 2020 from the same period in 2019 was primarily the result of changes to the variable portion of our incentive compensation program in May 2020, which was approved by the Bankruptcy Court, and a higher payout approved on pre-established performance metrics. For additional information on the variable compensation program, see Part I, Item 1 – Financial Statements, Note 1 Chapter 11 Proceedings and General above.

	Nine months ended September 30,
	2020		2019
	(in millions)
G&A expenses	$	193	$	228
Exclude: Stock-based compensation	(3)		(21)
Exclude: Other employee incentive awards	(42)		(30)
Exclude: Severance	—		(2)
G&A expenses, excluding employee incentive compensation and severance	$	148	$	175

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $61 million to $296 million for the nine months ended September 30, 2020 from to $357 million for the same period in 2019 was predominately due to a decrease in our depletable basis as a result of our asset impairment recorded in the first quarter of 2020.

Asset impairments — In the first quarter of 2020, we recorded an impairment charge of $1.7 billion, of which $1.5 billion related to certain of our proved properties and approximately $228 million related to unproved acreage that we no longer intend to pursue. No asset impairments were recorded in the second or third quarters of 2020. For further detail about our first quarter 2020 asset impairment, see Part I, Item 1 – Financial Statements, Note 15 Asset Impairments.

Marketing and trading costs — Marketing and trading costs decreased $103 million to $67 million for the nine months ended September 30, 2020 compared to $170 million in the same prior-year period. The decrease was predominantly the result of lower volume related to our natural gas trading activities.

Other expenses, net — The increase in other expenses of $42 million to $75 million for the nine months ended September 30, 2020 compared to $33 million for the same period of 2019 was largely the result of a one-time deficiency payment of $20 million made in April 2020 in connection with an expiring pipeline delivery contract and a scheduled plant turnaround at the Elk Hills power plant in the first quarter of 2020.

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Reorganization items, net — We recognized a $66 million net gain in the third quarter of 2020 primarily due to the write-off of the unamortized balance of deferred gain, original issue discounts and deferred issuance costs on our long-term debt partially offset by increased legal, professional and other fees, including debtor-in-possession financing costs, all of which related to our bankruptcy proceedings. See Part I, Item 1 – Financial Statements, Note 2 Basis of Presentation for additional information about reorganization items, net.

Interest and debt expense, net — Interest and debt expense, net decreased $93 million to $200 million in the nine months ended September 30, 2020 compared to $293 million in the same period of 2019 primarily due to suspending the accrual of interest on our pre-petition long-term debt obligations as of July 15, 2020, a lower overall debt balance primarily resulting from repayment of our 2020 Senior Notes in January 2020 and repurchases of our Second Lien Notes in 2019, and lower variable interest rates on borrowings under our 2016 Credit Agreement and 2017 Credit Agreement. This decrease was partially offset by interest on our debtor-in-possession financing. See Part I, Item 1 – Financial Statements, Note 6 Debt for additional information on our debtor-in-possession financing.

Net gain on early extinguishment of debt — The net gain on early extinguishment of debt for the nine months ended September 30, 2020 was $5 million, which is a decrease of $103 million from $108 million during the same period in 2019. The decrease was due to lower debt repurchase activity in 2020.

Other non-operating expense — Other non-operating expense increased $75 million to $93 million for the nine months ended September 30, 2020 compared to $18 million in the same period of 2019. The increase was primarily a result of legal, professional and other fees associated with the preparation of the Chapter 11 Cases, incurred prior to our petition date, as well as a one-time severance charge related to our August 2020 workforce reduction.

Net income attributable to noncontrolling interests — The increase of $12 million in net income attributable to noncontrolling interests to $97 million for the nine months ended September 30, 2020 from $85 million for the same period in 2019 was primarily a result of limitations on the amount of losses allocable to ECR's Class C member interest in 2020. See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information on the Ares JV.

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Non-GAAP Financial Measures

Adjusted net (loss) income — Our results of operations, which are presented in accordance with U.S. GAAP, can include the effects of unusual, out-of-period and infrequent transactions and events affecting earnings that vary widely and unpredictably (in particular certain non-cash items such as derivative gains and losses) in nature, timing, amount and frequency. Therefore, management uses a measure called adjusted net income (loss) that excludes those items. This measure is not meant to disassociate these items from management's performance but rather is meant to provide useful information to investors interested in comparing our performance between periods. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP.

The following table presents a reconciliation of the GAAP financial measure of net (loss) income to the non-GAAP financial measure of adjusted net (loss) income and presents the GAAP financial measure of net (loss) income attributable to common stock per diluted share and the non-GAAP financial measure of adjusted net (loss) income per diluted share:

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
	(in millions, except share data)
Net (loss) income	$	(7)	$	127	$	(1,999)	$	124
Net income attributable to noncontrolling interests	(22)		(33)		(97)		(85)
Net (loss) income attributable to common stock	(29)		94		(2,096)		39
Unusual, infrequent and other items:
Asset impairment	—		—		1,736		—
Non-cash derivative (loss) gain from commodities, excluding noncontrolling interest	(4)		6		31		99
Reorganization items, net:	(66)		—		(66)		—
Unamortized deferred gain	(171)		—		(171)		—
Unamortized deferred issuance costs and original issue discounts	46		—		46		—
Legal, professional and other items during bankruptcy, net	34		—		34		—
Debtor-in-possession financing costs	25		—		25		—
Severance and termination benefits	10		—		10		2
Incentive and retention award modification	—		—		4		—
Net gain on early extinguishment of debt	—		(82)		(5)		(108)
Legal, professional and other fees pre-bankruptcy	15		—		64		—
Deficiency payment on a pipeline delivery contract	—		—		20		—
Planned power plant maintenance	—		—		7		—
Write-off of deferred financing costs	4		—		4		—
Other, net	15		(1)		26		2
Total unusual, infrequent and other items	(26)		(77)		1,831		(5)
Adjusted net (loss) income	$	(55)	$	17	$	(265)	$	34
Net income (loss) attributable to common stock per diluted share(a)	2.20		1.89		(39.64)		0.77
Adjusted net income (loss) per diluted share(a)	1.68		0.35		(2.57)		0.69

(a) Net income (loss) and adjusted net income (loss) per diluted share for the three and nine months ended September 30, 2020 include a $138 million gain related to the deemed redemption of the noncontrolling interest in the Ares JV. See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information about our Settlement Agreement and the Ares JV.

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Adjusted EBITDAX — We define adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, out-of-period and infrequent items; and other non-cash items. We believe this measure provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry, the investment community and our lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. This measure should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

The following table presents a reconciliation of the GAAP financial measure of net (loss) income to the non-GAAP financial measure of adjusted EBITDAX:

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
	(in millions)
Net (loss) income	$	(7)	$	127	$	(1,999)	$	124
Interest and debt expense, net	28		95		200		293
Depreciation, depletion and amortization	89		118		296		357
Exploration expense	2		5		9		25
Unusual, infrequent and other items	(26)		(77)		1,831		(5)
Other non-cash items	17		10		36		40
Adjusted EBITDAX	$	103	$	278	$	373	$	834

The following table sets forth a reconciliation of the GAAP measure of net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX:

	Nine months ended September 30,
	2020		2019
	(in millions)
Net cash provided by operating activities	$	141	$	540
Cash interest	80		300
Exploration expenditures	9		15
Working capital changes, excluding accrued interest	143		(21)
Adjusted EBITDAX	$	373	$	834

Adjusted G&A — Management uses a measure called adjusted general and administrative (adjusted G&A) expense to provide useful information to investors interested in comparing our costs between periods and performance to our peers. We define adjusted G&A expenses as general and administrative expenses excluding severance and other non-recurring costs.

The following table presents the reconciliation of our general and administrative expenses to the non-GAAP measure of adjusted G&A:

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
General and administrative expenses	$	64	$	66	$	193	$	228
Incentive and retention award modification	—		—		(4)		—
Severance costs	—		(1)		—		(2)
Adjusted G&A	$	64	$	65	$	189	$	226

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Liquidity and Capital Resources

Cash Flow Analysis – Pre-Emergence

	Nine months ended September 30,
	2020		2019
	(in millions)
Cash flow from operating activities	$	141	$	540
Cash flow from investing activities:
Capital investments	$	(37)	$	(393)
Decreases in accrued capital investments	$	(25)	$	(49)
Acquisitions, divestitures and other	$	34	$	151
Cash flow from financing activities:
Net debt transactions	$	87	$	(178)
Net distributions to noncontrolling interest holders	$	(94)	$	(66)
Issuance of common stock and other	$	(1)	$	—

Cash flows from operating activities — Our net cash provided by operating activities is sensitive to many variables, including changes in commodity prices. Commodity price movements may also lead to changes in other variables in our business, including adjustments to our capital program. Our operating cash flow decreased 74%, or $399 million, to $141 million for the nine months ended September 30, 2020 from $540 million in the same period of 2019. The decrease in operating cash flow primarily reflected the significant drop in oil prices between periods. The decrease was partially offset by a positive $153 million change in operating assets and liabilities, net in the nine months ended September 30, 2020 compared to an increase of $55 million in the comparable nine months of 2019. The changes in operating assets and liabilities resulted from a decrease in accounts receivable due to lower commodity prices between periods and an increase in accrued liabilities related to our legal and professional fees, partially offset by a decrease related to suspending the accrual of interest on our long-term debt.

Cash flows from investing activities — Our net cash used in investing activities of $28 million for the nine months ended September 30, 2020 primarily reflected $37 million of capital investments (excluding a $25 million decrease in capital-related accrual changes). Investing activities also included proceeds of $41 million related to a sale of royalty interests and a non-core asset in the nine months ended September 30, 2020. For the nine months ended September 30, 2019, our net cash used in investing activities of $291 million primarily included approximately $393 million of capital investments (excluding a $49 million decrease in capital-related accrual changes), of which $48 million was funded by BSP, partially offset by $164 million of proceeds related to our Lost Hills sale.

Cash flows from financing activities — Our net cash used in financing activities of $8 million for the nine months ended September 30, 2020 primarily included $518 million in net repayments on our 2014 Revolving Credit Facility and net $733 million of proceeds from our debtor-in-possession financing. Financing activities also included $100 million for the repayment of the 2020 Senior Notes at maturity, $94 million of distributions to our noncontrolling interest holders, $25 million for our debtor-in-possession financing costs and $3 million for repurchases of our Second Lien Notes. For the nine months ended September 30, 2019, our net cash used in financing activities of $244 million was primarily comprised of $149 million used for repurchases of our Senior Notes, $115 million of distributions paid to our noncontrolling interest holders, and $27 million of net repayments on our 2014 Revolving Credit Facility partially offset by $49 million in a net contribution from a noncontrolling interest holder.

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Liquidity

During the pendency of the Chapter 11 Cases, our primary sources of liquidity were limited to cash flow from operations, cash on hand and available borrowing capacity under our Senior DIP Facility. After our emergence from Chapter 11, and repayment of the balances outstanding under our debtor-in-possession credit agreements, our primary sources of liquidity are comprised of cash flow from operations and availability under our new Revolving Credit Facility. We also may rely on other sources, such as non-core asset sales, to supplement our cash flow and fund other corporate purposes. We believe we have sufficient sources of cash to meet our obligations for the next twelve months.

Under our Revolving Credit Facility and Second Lien Term Loan, we will be subject to liquidity requirements under certain conditions. See Part I, Item 1 – Financial Statements, Note 6 Debt for additional information on the liquidity requirements under our credit agreements. As of the Effective Date (October 27, 2020), our liquidity was $350 million, which includes $72 million of unrestricted cash and approximately $278 million of availability on our Revolving Credit Facility.

Working Capital

Our working capital requirements are primarily driven by the level of activity in our business, commodity prices and debt service requirements.

Debt and Post-Emergence Capitalization

The commencement of our Chapter 11 Cases constituted an immediate event of default that automatically accelerated our long-term obligations. Any efforts to enforce payment obligations related to the acceleration of our obligations under our debt agreements were automatically stayed immediately upon filing the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

As of September 30, 2020, the outstanding principal of our long-term debt was $5.1 billion, of which $4.4 billion related to obligations that existed prior to our bankruptcy filing and approximately $700 million related to debtor-in-possession financing. Our outstanding pre-petition debt was presented as liabilities subject to compromise and our debtor-in-possession financing was presented in total current liabilities on our condensed consolidated balance sheet as of September 30, 2020.

In accordance with the Plan, confirmed by the Bankruptcy Court, significant transactions affecting our liquidity upon emergence from Chapter 11 included the following:

•Approximately $4.4 billion of pre-petition debt was exchanged for new common stock and Warrants;

•We borrowed $225 million on our Revolving Credit Facility, a portion of which was used to repay our Senior DIP Facility;

•Repaid our Junior DIP Facility with $450 million of proceeds from new equity issued under our Subscription Rights offering and $200 million of proceeds from our Second Lien Term Loan;

•Acquired all of the member interest in the Ares JV held by ECR in exchange for the EHP Notes, Ares Settlement Stock and $2.5 million in cash;

•Cash collateralized, on an interim basis, certain letters of credit for $118 million; and

•Funded $18 million into a restricted account for payment of certain legal, professional and other fees associated with our restructuring.

Following the Effective Date, cash interest will approximate $50 million per year. Distributions to noncontrolling interest holders will approximate $18 million per year, which is our required minimum distribution to BSP.

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The following table presents our pro forma capitalization after giving effect to certain transactions in the Plan, assuming our Effective Date was on September 30, 2020(a):

	Actual September 30, 2020		Reorganization Adjustments		Pro Forma
	($ in millions)
Senior DIP Facility	$	83	$	(83)	$	—
Junior DIP Facility	650		(650)		—
Total short-term borrowings	733		(733)		—
Revolving Credit Facility	—		225		225
Second Lien Term Loan	—		200		200
EHP Notes	—		300		300
2017 Credit Agreement	1,300		(1,300)		—
2016 Credit Agreement	1,000		(1,000)		—
Second Lien Notes	1,808		(1,808)		—
5% Senior Notes due 2020	—		—		—
5.5% Senior Notes due 2021	100		(100)		—
6% Senior Notes due 2024	144		(144)		—
Total long-term debt(b)	4,352		(3,627)		725
Mezzanine Equity
Redeemable noncontrolling interests(c)	692		$	(692)	—
Equity	(2,273)		$	5,052	2,779
Total Capitalization	$	3,504	$	—	$	3,504

(a)The above pro forma adjustments do not reflect all of the adjustments that would be required to present pro forma financial statements in accordance with Article 11 of Regulation S-X. For example, the effects of fresh start accounting have not been included.

(b)On the Effective Date, we had unrestricted cash of $72 million and an additional $118 million of cash temporarily used to collateralize letters of credit.

(c)See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for more information about our Settlement Agreement and the Ares JV.

For more information on our debt, see Part I, Item 1 – Financial Statements, Note 6 Debt and for more information on our confirmed Plan, see Part I, Item 1 – Financial Statements, Note 1 Chapter 11 Proceedings.

Derivatives

Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow, and the inverse applies during periods of rising commodity prices. To mitigate some of the risk inherent in the downward movement in oil prices, we may enter into various derivative instruments to hedge commodity price risk.

Commodity Contracts

In early March 2020, in response to the rapid fall in commodity prices, 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 $63 million to enhance our liquidity.

The Senior DIP Credit Agreement required 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, as shown in the table below, to satisfy this requirement. Our Revolving Credit Facility and our Second Lien Term Loan require us to maintain hedges on a notional amount of crude oil production as described in Part I, Item 1 – Financial Statements, Note 6 Debt. We are currently in the process of entering into additional oil hedges to meet the hedging requirement in our credit agreements.

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.

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At October 31, 2020, we had the following Brent-based crude oil contracts:

	Q4 2020		Q1 2021		Q2 2021		July 2021
Sold Calls:
Barrels per day	4,800		4,500		4,500		4,200
Weighted-average price per barrel	$	48.05	$	48.05	$	48.05	$	48.05
Purchased Puts:
Barrels per day	18,600		18,000		9,000		8,400
Weighted-average price per barrel	$	44.84	$	45.00	$	40.00	$	40.00
Sold Puts:
Barrels per day	13,800		13,500		4,500		4,200
Weighted-average price per barrel	$	36.52	$	36.67	$	30.00	$	30.00
Swaps:
Barrels per day	6,400		6,000		6,000		5,600
Weighted-average price per barrel	$	44.75	$	44.75	$	44.75	$	44.75

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.

We also currently have Brent-based crude oil contracts for insignificant volumes through May 2021 which were entered into by our BSP JV and are included in our consolidated results but not in the above table. The BSP JV also entered into natural gas swaps for insignificant volumes for periods through May 2021. The hedges entered into by the BSP JV could affect the timing of the redemption of the BSP preferred interest.

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2020 Capital Program

We entered 2020 with an internally funded capital program of $100 million to $300 million. In March 2020, we reduced our capital investment to a level that maintains the mechanical integrity of our facilities to operate in a safe and environmentally responsible manner in response to the collapse in crude oil prices. We made $37 million of internally funded capital investments in the first nine months of 2020 and we expect to invest an additional $10 million, primarily related to facilities, through the end of 2020. At this level of investment, we suspended all internally funded drilling and most capital workovers and significantly reduced other activities. The Board of Directors, which includes seven new directors appointed as of October 27, 2020, will review and determine our capital program for future periods.

Our JV partners invested $94 million in the first nine months of 2020. On March 27, 2020, Alpine elected to suspend its funding obligations under the Alpine JV. For further information, regarding the Alpine JV and its funding obligations, see the Development Joint Ventures section above.

The amounts in the table below reflect our consolidated capital investment, excluding changes in capital investment accruals, for the nine months ended September 30, 2020 and 2019:

	Nine months ended September 30,
	2020		2019
	(in millions)
Oil and natural gas	$	36	$	325
Exploration	—		9
Corporate and other	1		11
Total internally funded capital	37		345
BSP funded capital	—		48
Total consolidated capital investment	$	37	$	393

The curtailment of the development of our properties will lead to a decline in our production and may lower our reserves. A continued decline in our production and reserves would negatively impact our cash flow from operations and the value of our assets.

Regulation of the Oil and Natural Gas Industry

In September 2020, the Ventura County Board of Supervisors adopted an amended General Plan and approved an associated Environmental Impact Report (EIR) that impose significant restrictions on new discretionary development projects in Ventura County. With respect to new discretionary oil and gas development, the amended General Plan: requires setbacks of 1,500 feet and 2,500 feet from residences and schools, respectively; prohibits trucking of oil and produced water; restricts flaring; requires electrification of equipment; and requires additional reviews for projects involving well stimulation treatment or steam injection. Collectively, these restrictions would prevent or substantially reduce new development of at least five fields that we operate. The Board is also considering a proposed ordinance to unilaterally revoke or revise longstanding conditional use permits, thereby applying the amended General Plan to fields with existing permits. Multiple lawsuits have been filed challenging the amended General Plan and EIR, including by us, on numerous statutory and constitutional grounds.

Other government authorities have proposed or adopted new or more stringent requirements or restrictions on oil and gas operations and development, as described in the Regulatory section of our 2019 Form 10-K, and the Risk Factors in our 2019 Form 10-K and this Form 10-Q.

Seasonality

While certain aspects of our operations are affected by seasonal factors, such as energy costs, seasonality has not been a material driver of changes in our quarterly results.

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Lawsuits, Claims, Commitments and Contingencies

We 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 September 30, 2020 and December 31, 2019 were not material to our condensed consolidated balance sheets as of such dates. 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 be material to our consolidated financial position or results of operations.

Subject to certain exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases on July 15, 2020 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, government authorities may determine to continue actions brought under regulatory powers.

On October 13, 2020, the Bankruptcy Court confirmed our Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code, which was conditioned on certain items such as obtaining exit financing. On October 27, 2020 the conditions to effectiveness of the Plan were satisfied and we emerged from Chapter 11 on the Effective Date. Upon effectiveness of the Plan, the automatic stay discussed above no longer applies to ongoing judicial or administrative proceedings.

Significant Accounting and Disclosure Changes

See Part I, Item 1, Note 3 Accounting and Disclosure Changes for a discussion of new accounting matters.

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Forward-Looking Statements

The information included herein contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding our expectations as to our future:

•financial position, liquidity, cash flows and results of operations

•business prospects

•transactions and projects

•operating costs

•Value Creation Index (VCI) metrics, which are based on certain estimates including future production rates, costs and commodity prices

•operations and operational results including production, hedging and capital investment

•budgets and maintenance capital requirements

•reserves

•type curves

•expected synergies from acquisitions and joint ventures

Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-party statements we cite are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include:

•our ability to execute our business plan post-emergence

•the volatility of commodity prices and the potential for sustained low oil, natural gas and NGL prices

•impact of our recent emergence from bankruptcy on our business and relationships

•debt limitations on our financial flexibility

•insufficient cash flow to fund planned investments, debt repurchases or changes to our capital plan

•insufficient capital or liquidity, including as a result of lender restrictions, unavailability of capital markets or inability to attract potential investors

•limitations on transportation or storage capacity and the need to shut-in wells

•inability to enter into desirable transactions, including acquisitions, asset sales and joint ventures

•our ability to utilize our net operating loss carryforwards to reduce our income tax obligations

•limitations on the liquidity of our new common stock and volatility of its market price

•legislative or regulatory changes, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products

•joint ventures and acquisitions and our ability to achieve expected synergies

•the recoverability of resources and unexpected geologic conditions

•incorrect estimates of reserves and related future cash flows and the inability to replace reserves

•changes in business strategy

•PSC effects on production and unit production costs

•effect of stock price on costs associated with incentive compensation

•effects of hedging transactions

•equipment, service or labor price inflation or unavailability

•availability or timing of, or conditions imposed on, permits and approvals

•lower-than-expected production, reserves or resources from development projects, joint ventures or acquisitions, or higher-than-expected decline rates

•disruptions due to accidents, mechanical failures, power outages, transportation or storage constraints, natural disasters, labor difficulties, cyber-attacks or other catastrophic events

•pandemics, epidemics, outbreaks, or other public health events, such as the coronavirus disease (COVID-19)

•factors discussed in Item 1A, Risk Factors in our Annual Report on Form 10-K available at www.crc.com.

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Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would" and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

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Item 3Quantitative and Qualitative Disclosures About Market Risk

For the three and nine months ended September 30, 2020, there were no material changes to commodity price risk, interest rate risk or counterparty credit risk from the information provided under Item 305 of Regulation S-K included under the caption Management's Discussion and Analysis of Financial Condition and Results of Operations (Incorporating Item 7A) – Quantitative and Qualitative Disclosures About Market Risk in the 2019 Form 10-K, except as discussed below.

Commodity Price Risk

The Senior DIP Credit Agreement required 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 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.

Our oil hedge positions at October 31, 2020, as shown in the table below, provide for the following expected outcomes:

	Q4 2020	Q1 2021	Q2 2021	July 2021
Barrels per day	13,800	13,500	4,500	4,200
	Receive Brent if Brent > $46.52	Receive Brent if Brent > $46.67	Receive Brent if Brent > $40	Receive Brent if Brent > $40
	Receive $46.52 if Brent between $46.52 and $36.52	Receive $46.67 if Brent between $46.67 and $36.67	Receive $40 if Brent between $30 and $40	Receive $40 if Brent between $30 and $40
	Receive Brent +$10 if Brent <$36.52	Receive Brent +$8.33 if Brent <$36.67	Receive Brent +$10 if Brent <$30	Receive Brent +$10 if Brent <$30
Barrels per day	4,800	4,500	4,500	4,200
	Ceiling price of $48.05 Brent	Ceiling price of $48.05 Brent	Ceiling price of $48.05 Brent	Ceiling price of $48.05 Brent
	Receive Brent between $40 and $48.05	Receive Brent between $40 and $48.05	Receive Brent between $40 and $48.05	Receive Brent between $40 and $48.05
	Floor price of $40 Brent	Floor price of $40 Brent	Floor price of $40 Brent	Floor price of $40 Brent
Barrels per day	6,400	6,000	6,000	5,600
	Receive $44.75 Brent at all prices	Receive $44.75 Brent at all prices	Receive $44.75 Brent at all prices	Receive $44.75 Brent at all prices

Our post-emergence Revolving Credit Facility and our Second Lien Term Loan require us to maintain hedges on part of our crude oil production as described in Part I, Item 1 – Financial Statements, Note 6 Debt. We are currently in the process of entering into additional oil hedges to meet the hedging requirement in our credit agreements.

We also currently have Brent-based crude oil contracts for insignificant volumes through May 2021 which were entered into by our BSP JV and are included in our consolidated results but not in the above table. The BSP JV also entered into natural gas swaps for insignificant volumes for periods through May 2021. The hedges entered into by the BSP JV could affect the timing of the redemption of the BSP preferred interest.

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Counterparty Credit Risk

Our credit risk relates primarily to trade receivables and derivative financial instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. For derivative instruments entered into as part of our hedging program, we are subject to counterparty credit risk to the extent the counterparty is unable to meet its settlement commitments. We actively manage this credit risk by selecting counterparties that we believe to be financially strong and continuing to monitor their financial health. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.

As of September 30, 2020, the substantial majority of the credit exposures related to our business was with investment-grade counterparties. We believe exposure to counterparty credit-related losses related to our business at September 30, 2020 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

Interest-Rate Risk

On July 15, 2020, we filed for relief under Chapter 11 of the Bankruptcy Code and as a result interest on our pre-petition debt is limited to what is determined by the Bankruptcy Court to be an allowed claim. On July 23, 2020, we entered into debtor-in-possession credit agreements, which carry variable interest rates. Our debtor-in-possession credit agreements were repaid subsequent to September 30, 2020 (on our Effective Date) and replaced with our new Revolving Credit Facility, Second Lien Term Loan and EHP Notes. Our Revolving Credit Facility and Second Lien Term Loan carry variable interest rates. A one-eighth percent change in the interest rates on the outstanding borrowings under these facilities at October 27, 2020, excluding $118 million of cash temporarily used to collateralize letters of credit, would result in an approximately $400,000 change in annual interest expense assuming no payments are received under our interest-rate cap agreements described below. See Part I, Item 1 – Financial Statements, Note 6 Debt for additional information on our debtor-in-possession financing and post-emergence indebtedness.

In March 2018, we entered into derivative contracts that limit our interest-rate exposure with respect to $1.3 billion of our variable-rate indebtedness. The 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 4, 2021. No settlement payments were received in either 2020 or 2019.

Item 4 Controls and Procedures

Our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer supervised and participated in our evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2020.

We have appropriately implemented Financial Accounting Standards Board Accounting Standards Codification 852, Reorganizations (ASC 852) during the quarter and have prepared the interim condensed consolidated financial statements and disclosures in accordance with ASC 852.

There were no changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the three months ended September 30, 2020 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II    OTHER INFORMATION

Item 1Legal Proceedings

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Chapter 11 Cases filed by us were jointly administered under the caption In re California Resources Corporation, et al., Case No. 20-33568 (DRJ). See Part I, Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, General, Chapter 11 Proceedings for more information.

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, government authorities may determine to continue actions brought under regulatory powers.

On October 13, 2020, the Bankruptcy Court confirmed our Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code, which was conditioned on certain items such as obtaining exit financing. On October 27, 2020 the conditions to effectiveness of the Plan were satisfied and we emerged from Chapter 11 on the Effective Date. Upon effectiveness of the Plan, the automatic stay discussed above no longer applies to ongoing judicial or administrative proceedings.

For additional information regarding legal proceedings, see Item 1 – Financial Statements, Note 8 Lawsuits, Claims, Commitments and Contingencies in the Notes to the Condensed Consolidated Financial Statements included in Part I of this Form 10-Q, Part I, Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Lawsuits, Claims, Commitments and Contingencies in this Form 10-Q, and Part I, Item 3, Legal Proceedings in our Form 10-K for the year ended December 31, 2019.

Item 1A     Risk Factors

We are subject to various risks and uncertainties in the course of our business. A discussion of such risks and uncertainties may be found under the heading Risk Factors in our Form 10-K for the year ended December 31, 2019. Other than as provided below, there were no material changes to those risk factors during the nine months ended September 30, 2020.

Recent actions by the Governor of California could result in restrictions to our operations and result in decreased demand for oil and gas within the state.

In September 2020, Governor Gavin Newsom of California issued an executive order (Order) that seeks to reduce both the demand for and supply of petroleum fuels in the state. The Order establishes several goals and directs several state agencies to take certain actions with respect to reducing emissions of greenhouse gases, including, but not limited to: phasing out the sale of new emissions-producing passenger vehicles, drayage trucks and off-road vehicles by 2035 and medium and heavy duty trucks by 2045, where feasible; developing strategies for the closure and repurposing of oil and gas facilities in California; and proposing legislation to end the issuance of new hydraulic fracturing permits in the state by 2024. The Order also directs the California Department of Conservation, Geologic Energy Management Division (CalGEM) to strictly enforce bonding requirements for oil and gas operations and to complete its ongoing public health and safety review of oil production and propose additional regulations, which may include expanded land use setbacks, by December 31, 2020. In October 2020, the Governor issued an executive order that establishes a state goal to conserve at least 30% of California’s land and coastal waters by 2030 and directs state agencies to implement other measures to mitigate climate change and strengthen biodiversity. Any of the foregoing developments may materially and adversely affect our operations and properties and the demand for our products.

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The COVID-19 pandemic has caused crude oil prices to decline significantly in 2020, which has materially and adversely affected our business, results of operation, financial condition and liquidity.

The COVID-19 pandemic has adversely affected the global economy, and has resulted in, among other things, travel restrictions, business closures and the institution of quarantining and other mandated and self-imposed restrictions on movement. As a result, there has been an unprecedented reduction in demand for crude oil. In March 2020, crude oil prices declined significantly as a result of market concerns about the economic impact from the COVID-19 pandemic, restrictions and other measures implemented in response to the pandemic as well as certain actions of OPEC, Russia and other foreign oil producers. In April 2020, oil prices continued to decline precipitously reaching negative prices for spot WTI crude. The severity, magnitude and duration of current or future COVID-19 outbreaks, the extent of actions that have been or may be taken to contain or treat their impact, and the impacts on the economy generally and oil prices in particular, are uncertain, rapidly changing and hard to predict. The current futures forward curve for Brent crude indicates that relatively lower prices may continue for an extended period of time. As a result, we reduced our operating expenses and planned capital expenditures to those necessary to maintain mechanical integrity of our facilities to operate them in a safe and environmentally responsible manner. In addition, we have shut-in wells which reduced our third quarter 2020 net production by 3 MBoe/d. These operational decisions starting in March 2020 have negatively impacted our production and may materially and adversely affect the quantity of estimated proved reserves that may be attributed to our properties. Our operations also may be adversely affected if significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions or other restrictions in connection with the pandemic. In addition, we are exposed to changes in commodity prices which have been and will likely remain volatile and relatively lower for the foreseeable future.

The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil in the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. There can be no assurances that OPEC members and other oil exporting nations will agree to future production cuts or other actions to support and stabilize oil prices, nor can there be any assurances that they will not further reduce oil prices or increase production. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil and natural gas, which could adversely affect our business, financial condition, results of operations and cash flows.

We recently emerged from bankruptcy, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 Cases could adversely affect our business and relationships with customers, employees, suppliers and government authorities. Due to uncertainties, many risks exist, including the following:

•key suppliers could terminate their relationship or require financial assurances or enhanced performance;

•the ability to renew existing contracts and compete for new business may be adversely affected;

•the ability to attract, motivate and/or retain key executives and employees may be adversely affected;

•employees may be distracted from performance of their duties or more easily attracted to other employment opportunities;

•competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted; and

•the ability to obtain permits and approvals from government authorities for existing and new development projects may be affected, or may be subject to additional financial assurance or other conditions that may not be feasible.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

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Even though the Plan has been consummated, we may not be able to achieve our stated goals.

Even though the Plan has been consummated, we may continue to face a number of risks, such as further deterioration or other changes in economic conditions, changes in our industry, changes in demand for our products and services and increasing expenses. Accordingly, we cannot guarantee that the Plan will achieve our stated goals.

Furthermore, even though our debts were reduced through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the Chapter 11 Cases. Our access to additional financing may be limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms.

Our lenders could limit our borrowing capabilities and restrict our ability to use or access capital.

Our Revolving Credit Facility is an important source of our liquidity. Our ability to borrow under our Revolving Credit Facility is limited by our borrowing base, the size of our lenders' commitments and our ability to comply with covenants, including various leverage ratios, hedging requirements and reporting obligations.

The borrowing base under our Revolving Credit Facility is redetermined semi-annually on April 1 and October 1. Our lenders determine our borrowing base by reference to the value of our reserves and other factors that the administrative agent may deem appropriate in good faith in accordance with its usual and customary oil and gas lending criteria as they exist at the particular time. The lenders under our Revolving Credit Facility may also factor other liabilities, including our other indebtedness, into the determination of our borrowing base. Currently, our borrowing base is set at $1.2 billion. Availability under our Revolving Credit Facility is the least of (i) the then-effective borrowing base, (ii) the then-effective aggregate commitments and (iii) the aggregate elected commitment amount, which is currently set at $540 million.

Any reduction in our borrowing base could materially and adversely affect our liquidity and may hinder our ability to execute on our business strategy.

For a further description of our Revolving Credit Facility and our other credit agreements, see Part I, Item 1 – Financial Statements, Note 6 Debt and the documents governing our indebtedness that are filed with the SEC.

Restrictive covenants in our credit facilities may limit our financial and operating flexibility.

As of the Effective Date, we had approximately $225 million of outstanding indebtedness under our Revolving Credit Facility, $200 million of outstanding indebtedness under our Second Lien Term Loan and $300 million under our EHP Notes. Our financing agreements permit us to incur significant additional indebtedness as well as certain other obligations. In addition, we may seek amendments or waivers from our existing lenders to the extent we need to incur indebtedness above amounts currently permitted by our financing agreements.

Our credit facilities contain certain restrictions, which may have adverse effects on our business, financial condition, cash flows or results of operations, limiting our ability, among other things, to:

•incur additional indebtedness;

•incur additional liens;

•pay dividends or make other distributions;

•make investments, loans or advances;

•sell or discount receivables;

•enter into mergers;

•sell properties;

•terminate swap agreements;

•enter into transactions with affiliates;

•maintain gas imbalances;

•enter into take-or-pay contracts or make other prepayments;

•enter into swap agreements;

•enter into sale and leaseback agreements;

•amend our organizational documents; and

•make capital investments.

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The credit facilities also require us to comply with certain financial maintenance covenants as discussed above including a leverage ratio and current ratio. See Part I, Item 1 – Financial Statements, Note 6 Debt for additional information.

A breach of any of these restrictive covenants could result in a default under the credit facilities. If a default occurs, the lenders may elect to declare all borrowings thereunder outstanding, together with accrued interest and other fees, to be immediately due and payable. If we are unable to repay our indebtedness when due or declared due, the lenders thereunder will also have the right to proceed against the collateral pledged to them to secure the indebtedness.

There may be a limited trading market for our securities and the market price of our securities is subject to volatility.

Upon our emergence from bankruptcy, our old common stock was cancelled and we issued new common stock, which is listed on the NYSE under the ticker “CRC”. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by our Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our common stock, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results. No assurances can be given that an active market will develop for the common stock or as to the liquidity of the trading market for the common stock. Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.

Our business requires substantial capital investments, which may include acquisitions or JVs. We may be unable to fund these investments which could lead to a decline in our oil and natural gas reserves or production. Our capital investment program is also susceptible to risks that could materially affect its implementation.

Our exploration, development and acquisition activities require substantial capital investments. Following our emergence from Chapter 11 restructuring, our capital investments will mainly be funded through a combination of cash flow from operations, borrowings under our credit facilities and joint ventures. We seek to manage our internally funded capital investments to closely align with projected cash flow from operations. Accordingly, a reduction in projected operating cash flow could cause us to reduce our future capital investments. In general, the ability to execute our capital plan depends on a number of factors, including:

•the amount of oil, natural gas and NGLs we are able to produce;

•commodity prices;

•regulatory and third-party approvals;

•our ability to timely drill, complete and stimulate wells;

•our ability to secure equipment, services and personnel; and

•the availability of external sources of financing.

Access to future capital may be limited by our lenders, our JV partners, capital markets constraints, activist funds or investors, or poor stock price performance. Because of these and other potential variables, we may be unable to deploy capital in the manner planned, which may negatively impact our production levels and development activities and limit our ability to make acquisitions or enter into JVs.

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Unless we make sufficient capital investments and conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our ability to make the necessary long-term capital investments or acquisitions needed to maintain or expand our reserves may be impaired to the extent we have insufficient cash flow from operations or liquidity to fund those activities. Over the long term, a continuing decline in our production and reserves would reduce our liquidity and ability to satisfy our debt obligations by reducing our cash flow from operations and the value of our assets.

Our commodity-price risk-management activities may prevent us from fully benefiting from price increases and may expose us to other risks.

Our commodity-price risk-management activities may prevent us from realizing the full benefits of price increases above any levels set in certain derivative instruments we may use to manage price risk. In addition, our commodity-price risk-management activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements.

Under our credit facilities, we are required to maintain acceptable commodity hedges hedging 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. Our credit facilities specify the forms of hedges and prices (which can be prevailing prices) that must be used. In addition, for the first 24 months after closing an additional 25% of production from proved reserves needs to be hedged, which may take any form.

We must also maintain acceptable commodity hedges for no less than 50% of the reasonably anticipated total forecasted production of crude oil from our oil and gas properties for at least 24 months following the date of delivery of each reserve report. We may not hedge more than 80% of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids from our oil and gas properties for a 48-month period following the date of entry into any commodity hedging contract.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), enacted in 2010, established federal oversight and regulation of the over-the-counter (OTC) derivatives market and entities, like us, that participate in that market. Among other things, the Dodd-Frank Act required the U.S. Commodity Futures Trading Commission to promulgate a range of rules and regulations applicable to OTC derivatives transactions. These regulations may affect both the size of positions that we may enter and the ability or willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, the effects of these regulations could reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices.

In addition, U.S. regulators adopted a final rule in November 2019 implementing a new approach for calculating the exposure amount of derivative contracts under the applicable agencies’ regulatory capital rules, referred to as the standardized approach for counterparty credit risk (SA-CCR). Certain financial institutions are required to comply with the new SA-CCR rules beginning on January 1, 2022. The new rules could significantly increase the capital requirements for certain participants in the over-the-counter derivatives market in which we participate. These increased capital requirements could result in significant additional costs being passed through to end-users like us or reduce the number of participants or products available to us in the over-the-counter derivatives market. These regulations could result in a reduction in our hedging opportunities or substantially increase our cost of hedging, which could adversely affect our business, financial condition and results of operations.

The European Union and other non-U.S. jurisdictions may implement regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to or otherwise impacted by such regulations, which could also adversely affect our hedging opportunities.

Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of our Plan and the transactions contemplated thereby and our adoption of fresh start accounting.

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In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of our Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of our Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, upon our emergence from bankruptcy, we believe that we are required to adopt fresh start accounting. Accordingly, our future financial statements may not be comparable to our historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our common stock.

Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

Pursuant to our Plan, the composition of our Board of Directors changed significantly. On October 27, 2020, seven new non-employee directors were appointed to our Board of Directors in connection with our emergence from bankruptcy. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the board and, thus, may have different views on the issues that will determine our future. There is no guarantee that the new board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and our plans may differ materially from those of the past.

Our Board of Directors has not adopted a dividend policy.

Our Board of Directors, which includes seven new directors appointed as of October 27, 2020, has not adopted a dividend policy. There can be no assurances that it will adopt a policy that contemplates paying cash dividends or other distributions with respect to our common stock, or authorize share repurchases. In addition, restrictive covenants in certain debt instruments to which we are, or may be, a party, may limit our ability to pay dividends or engage in share repurchases, which may negatively impact the trading price of our common stock.

The exercise of all or any number of outstanding warrants and the grant of equity awards under our management incentive plan may dilute your holding of shares of our common stock.

As of the date of filing this Quarterly Report, we have outstanding (i) Tier 1 Warrants representing the right to acquire in the aggregate up to 2% of shares of our common stock upon exercise, and (ii) Tier 2 Warrants representing the right to acquire in the aggregate up to 3% shares of our common stock upon exercise. The exercise of equity awards, including any stock options that we may grant in the future, and warrants, and the sale of shares of our common stock underlying any such options or the warrants, could have an adverse effect on the market for our common stock, including the price that an investor could obtain for their shares. Investors may experience dilution in the net tangible book value of their investment upon the exercise of the warrants and any stock options that may be granted or issued pursuant to the warrants in the future.

Future sales or the availability for sale of substantial amounts of our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and could impair our ability to raise capital through future sales of equity securities.

Our Amended and Restated Certificate of Incorporation authorizes us to issue 200 million shares of common stock, of which 83.3 million shares were outstanding as of the Effective Date. In addition, the Warrants issued pursuant to the Plan are exercisable for up to 5% of our outstanding common stock on a fully diluted basis as of the Effective Date. Shares issued upon exercise of these Warrants will generally be freely transferable without restriction or registration under the Securities Act pursuant to Section 1145 of the Bankruptcy Code.

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A large percentage of our shares of common stock are held by a relatively small number of investors. We entered into a registration rights agreement with those and other investors in connection with our emergence from Chapter 11 restructuring. Sales of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur, could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.

We may issue shares of our common stock or other securities from time to time as consideration for future acquisitions and investments. If any such acquisition or investment is significant, the number of shares of our common stock, or the number or aggregate principal amount, as the case may be, of other securities that we may issue may in turn be substantial. We may also grant registration rights covering those shares of our common stock or other securities in connection with any such acquisitions and investments.

We cannot predict the effect that future sales of our common stock will have on the price at which our common stock trades or the size of future issuances of our common stock or the effect, if any, that future issuances will have on the market price of our common stock. Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect the trading price of our common stock.

Certain provisions of our Charter and our Bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.

Certain provisions of our Amended and Restated Certificate of Incorporation (Charter) and our Amended and Restated Bylaws (Bylaws), both of which were adopted on our Effective Date, may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of us and our stockholders. The provisions in our Charter and Bylaws include, among other things, those that:

•authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;

•establish advance notice procedures for nominating directors or presenting matters at stockholder meetings;

•prohibit stockholders from taking actions by written consent and from calling special meetings;

•require a supermajority vote for stockholders to amend certain provisions of the Charter;

•prohibit cumulative voting;

•give the incumbent directors the exclusive power to fix the board size and fill vacancies on the board;

•require a supermajority vote for stockholders to remove any director without cause;

•elect to be subject to Section 203 of the General Corporation Law of the State of Delaware; and

•designate courts in Delaware as the exclusive forum for certain derivative actions and certain other actions against us or our directors and officers.

While these provisions have the effect of encouraging persons seeking to acquire control of CRC to negotiate with our board, they could enable the board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our board, which is responsible for appointing the members of our management.

Item 5     Other Disclosures

None.

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Item 6 Exhibits

2.1	Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed October 19, 2020 and incorporated herein by reference).
3.1	Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 to Registrant’s Registration Statement on Form 8-A filed 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).
10.1	Separation Agreement and General Release, dated August 18, 2020, by and between Marshall D. Smith and California Resources Corporation (filed as Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed August 18, 2020 and incorporated herein by reference).
10.2	Form of Indemnification Agreement by and between California Resources Corporation and its directors and executive officers (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed October 27, 2020 and incorporated herein by reference).
10.3	Registration Rights Agreement, dated as of October 27, 2020, by and among California Resources Corporation and the holders party thereto (filed as Exhibit 10.1 to the Registrant’s Registration Statement on Form 8-A filed October 27, 2020 and incorporated herein by reference).
10.4	Credit Agreement, dated as of October 27, 2020, by and among California Resources Corporation, as the Borrower, the several lenders from time to time parties thereto and Citibank, N.A., as Administrative Agent, Collateral Agent and an Issuing Bank (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed November 2, 2020 and incorporated herein by reference).
10.5	Credit Agreement, dated as of October 27, 2020, by and among California Resources Corporation, as the Borrower, the several lenders from time to time parties thereto and Alter Domus Products Corp., as Administrative Agent and Collateral Agent (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed November 2, 2020 and incorporated herein by reference).
10.6	Warrant Agreement, dated as of October 27, 2020, by and between California Resources Corporation and American Stock Transfer & Trust Company, LLC, as Warrant Agent (filed as Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed November 2, 2020 and incorporated herein by reference).
10.7	Note Purchase Agreement, dated as of October 27, 2020, by and among EHP Midco Holding Company, LLC, each of the Purchasers party thereto and Wilmington Trust, National Association, as Administrative Agent for the holders and as Collateral Agent for the secured parties (filed as Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed November 2, 2020 and incorporated herein by reference).
10.8	Owner Guaranty, dated as of October 27, 2020, by California Resources Corporation to and for the benefit of Wilmington Trust, National Association, as Collateral Agent for the secured parties (filed as Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed November 2, 2020 and incorporated herein by reference).
10.9	Sponsor Support Agreement, dated as of October 27, 2020, by and among Elk Hills Power, LLC, California Resources Corporation and EHP Midco Holding Company, LLC (filed as Exhibit 10.7 to the Registrant’s Current Report on Form 8-K filed November 2, 2020 and incorporated herein by reference).
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.
99.1	Order of the Bankruptcy Court, dated October 13, 2020, confirming the Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (filed as Exhibit 99.1 to the Registrant's Current Report on Form 8-K filed October 19, 2020 and incorporated herein by reference).
101.INS*	Inline XBRL Instance Document.

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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).

* - Filed herewith

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CALIFORNIA RESOURCES CORPORATION

DATE:	November 5, 2020	/s/ Roy M. Pineci
		Roy M. Pineci
		Senior Vice President - Finance
		(Principal Accounting Officer)

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