California Resources Corp - Quarter Report: 2021 June (Form 10-Q)

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 June 30, 2021

☐ 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 as of June 30, 2021 was 81,879,457.

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	21
	General	21
	Business Environment and Industry Outlook	21
	Production	22
	Prices and Realizations	24
	Statements of Operations Analysis	26
	Liquidity and Capital Resources	31
	2021 Capital Program	34
	Regulatory Update	34
	Share Repurchase Program	34
	Divestitures	34
	Acquisitions and Joint Ventures	35
	Seasonality	35
	Fixed and Variable Costs	35
	Lawsuits, Claims, Commitments and Contingencies	36
	Significant Accounting and Disclosure Changes	36
	Forward-Looking Statements	37
Item 3	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4	Controls and Procedures	39

Part II
Item 1	Legal Proceedings	40
Item 1A	Risk Factors	40
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 5	Other Disclosures	40
Item 6	Exhibits	41

PART I FINANCIAL INFORMATION

Item 1Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of June 30, 2021 and December 31, 2020

(in millions, except share data)


	Successor
	June 30,		December 31,
	2021		2020
CURRENT ASSETS
Cash	$	151	$	28
Trade receivables	238		177
Inventories	58		61
Assets held for sale	50		—
Other current assets	80		63
Total current assets	577		329
PROPERTY, PLANT AND EQUIPMENT	2,711		2,689
Accumulated depreciation, depletion and amortization	(138)		(34)
Total property, plant and equipment, net	2,573		2,655
OTHER ASSETS	90		90
TOTAL ASSETS	$	3,240	$	3,074


CURRENT LIABILITIES



Accounts payable	248		212
Liabilities associated with assets held for sale	101		—
Accrued liabilities	537		261
Total current liabilities	886		473
LONG-TERM DEBT, NET	589		597

OTHER LONG-TERM LIABILITIES	850		822



STOCKHOLDERS' EQUITY
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at June 30, 2021 and December 31, 2020	—		—
Common stock (200,000,000 shares authorized at $0.01 par value) issued shares (83,319,660 at June 30, 2021 and December 31, 2020)	1		1
Treasury stock (1,440,203 shares held at cost at June 30, 2021 and no shares held at December 31, 2020)	(45)		—
Additional paid-in capital	1,273		1,268
Accumulated deficit	(328)		(123)
Accumulated other comprehensive loss	(8)		(8)
Total equity attributable to common stock	893		1,138
Equity attributable to noncontrolling interests	22		44
Total stockholders' equity	915		1,182
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,240	$	3,074

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

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

(dollars in millions, except per share data)


	Successor		Predecessor		Successor		Predecessor
	Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,
	2021		2020		2021		2020
REVENUES
Oil, natural gas and natural gas liquids (NGL) sales	$	478	$	245	$	910	$	675
Net derivative (loss) gain from commodity contracts	(265)		(4)		(478)		75
Trading revenue	48		14		146		59
Electricity sales	33		19		66		32
Other revenue	10		2		23		8
Total revenues	304		276		667		849

COSTS
Operating costs	169		127		333		319
General and administrative expenses	48		69		96		129
Depreciation, depletion and amortization	54		88		106		207
Asset impairments	—		—		3		1,736
Taxes other than on income	37		38		77		79
Exploration expense	2		2		4		7
Trading costs	30		8		91		32
Electricity cost of sales	17		14		41		30
Transportation costs	14		8		26		21
Other expenses, net	23		37		53		53
Total costs	394		391		830		2,613

OPERATING LOSS	(90)		(115)		(163)		(1,764)

NON-OPERATING (LOSS) INCOME
Reorganization items	(2)		—		(4)		—
Interest and debt expense, net	(13)		(85)		(26)		(172)
Net (loss) gain on early extinguishment of debt	—		—		(2)		5
Other non-operating expenses	(2)		(47)		(1)		(61)
LOSS BEFORE INCOME TAXES	(107)		(247)		(196)		(1,992)
Income tax	—		—		—		—
NET LOSS	(107)		(247)		(196)		(1,992)

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
Mezzanine equity	—		(30)		—		(60)
Stockholders' equity	(4)		6		(9)		(15)
Net income attributable to noncontrolling interests	(4)		(24)		(9)		(75)
NET LOSS ATTRIBUTABLE TO COMMON STOCK	$	(111)	$	(271)	$	(205)	$	(2,067)

Net loss attributable to common stock per share
Basic	$	(1.34)	$	(5.47)	$	(2.46)	$	(41.84)
Diluted	$	(1.34)	$	(5.47)	$	(2.46)	$	(41.84)

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Comprehensive Income (Loss)

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

(dollars in millions)


	Successor		Predecessor		Successor		Predecessor
	Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,
	2021		2020		2021		2020
Net loss	$	(107)	$	(247)	$	(196)	$	(1,992)
Net income attributable to noncontrolling interests	(4)		(24)		(9)		(75)


Comprehensive loss attributable to common stock	$	(111)	$	(271)	$	(205)	$	(2,067)

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Equity

For the three and six months ended June 30, 2021

(dollars in millions)


	Three months ended June 30, 2021 (Successor)
	Common Stock		Treasury Stock		Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity
Balance, March 31, 2021	$	1	$	—	$	1,270	$	(217)	$	(8)	$	1,046	$	35	$	1,081
Net (loss) income(a)	—		—		—		(111)		—		(111)		4		(107)

Distributions to noncontrolling interest holders	—		—		—		—		—		—		(17)		(17)
Share-based compensation	—		—		3		—		—		3		—		3



Repurchases of common stock	—		(45)		—		—		—		(45)		—		(45)


Balance, June 30, 2021	$	1	$	(45)	$	1,273	$	(328)	$	(8)	$	893	$	22	$	915


	Six months ended June 30, 2021 (Successor)
	Common Stock		Treasury Stock		Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity
Balance, December 31, 2020	$	1	$	—	$	1,268	$	(123)	$	(8)	1,138		$	44	$	1,182
Net (loss) income(a)	—		—		—		(205)		—		(205)		9		(196)

Distributions to noncontrolling interest holders	—		—		—		—		—		—		(31)		(31)
Share-based compensation	—		—		5		—		—		5		—		5



Repurchases of common stock	—		(45)		—		—		—		(45)		—		(45)


Balance, June 30, 2021	$	1	$	(45)	$	1,273	$	(328)	$	(8)	$	893	$	22	$	915

(a)For the three and six months ended June 30, 2021, we allocated $4 million and $9 million of net income to noncontrolling interest holders, respectively, with the remaining $111 million and $205 million of net loss attributed to holders of our common stock, both of which were included in stockholders' equity on our condensed consolidated balance sheet.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Equity

For the three and six months ended June 30, 2020

(dollars in millions)


	Three months ended June 30, 2020 (Predecessor)
	Common Stock		Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity		Redeemable Noncontrolling Interests(b)
Balance, March 31, 2020	$	—	$	5,006	$	(7,166)	$	(23)	(2,183)		$	88	$	(2,095)	$	816
Net (loss) income(a)	—		—		(271)		—		(271)		(6)		(277)		30

Distributions to noncontrolling interest holders	—		—		—		—		—		(6)		(6)		(18)
Share-based compensation, net	—		2		—		—		2		—		2		—






Balance, June 30, 2020	$	—	$	5,008	$	(7,437)	$	(23)	$	(2,452)	$	76	$	(2,376)	$	828


	Six months ended June 30, 2020 (Predecessor)
	Common Stock		Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity		Redeemable Noncontrolling Interests(b)
Balance, December 31, 2019	$	—	$	5,004	$	(5,370)	$	(23)	(389)		$	93	$	(296)	$	802
Net (loss) income(a)	—		—		(2,067)		—		(2,067)		15		(2,052)		60
Contributions from noncontrolling interest holders			—		—		—		—				—		2
Distributions to noncontrolling interest holders	—		—		—		—		—		(32)		(32)		(36)
Share-based compensation, net	—		4		—		—		4		—		4		—






Balance, June 30, 2020	$	—	$	5,008	$	(7,437)	$	(23)	$	(2,452)	$	76	$	(2,376)	$	828

(a)For the three months ended June 30, 2020, we allocated $24 million of net income to noncontrolling interest holders, of which a $6 million net loss was included in stockholders' equity and $30 million was included in mezzanine equity on our condensed consolidated balance sheet. The remaining net loss of $271 million for the three months ended June 30, 2020 was attributed to holders of our common stock and included in stockholders' equity on our condensed consolidated balance sheet. For the six months ended June 30, 2020, we allocated $75 million of net income to noncontrolling interest holders, of which $15 million was included in stockholders' equity and $60 million was included in mezzanine equity on our condensed consolidated balance sheet. The remaining net loss of $2,067 million for the six months ended June 30, 2020 was attributed to holders of our common stock and included in stockholders' equity on our condensed consolidated balance sheet.

(b)Redeemable noncontrolling interests are reported in mezzanine equity on our condensed consolidated balance sheets in Predecessor periods. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our Annual Report on Form 10-K for the year ended December 31, 2020 for more information about our noncontrolling interests in the Ares and Elk Hills Carbon joint ventures.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

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

(dollars in millions)


	Successor		Predecessor		Successor		Predecessor
	Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,
	2021		2020		2021		2020
CASH FLOW FROM OPERATING ACTIVITIES
Net loss	$	(107)	$	(247)	$	(196)	$	(1,992)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	54		88		106		207
Asset impairments	—		—		3		1,736
Net derivative loss (gain) from commodity contracts	265		4		478		(75)
Net (payments) proceeds from settled commodity derivatives	(82)		5		(121)		103
Net loss (gain) on early extinguishment of debt	—		—		2		(5)
Amortization of deferred gain	—		(16)		—		(33)
Gain on asset divestiture	—		—		(2)		—



Other non-cash charges to income, net	22		14		29		22
Changes in operating assets and liabilities, net	(25)		17		(25)		130
Net cash provided by (used in) operating activities	127		(135)		274		93

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(50)		(3)		(77)		(33)
Changes in accrued capital investments	8		(9)		13		(28)
Proceeds from asset divestitures	—		—		2		41

Other	(1)		(3)		(1)		(7)
Net cash used in investing activities	(43)		(15)		(63)		(27)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from Revolving Credit Facility	—		—		16		—
Repayments of Revolving Credit Facility	—		—		(115)		—
Proceeds from 2014 Revolving Credit Facility	—		346		—		795
Repayments of 2014 Revolving Credit Facility	—		(123)		—		(582)
Proceeds from Senior Notes	—		—		600		—
Debt repurchases	—		—		—		(3)
Debt issuance costs	(1)		—		(13)		—
Repayment of Second Lien Term Loan	—		—		(200)		—
Repayment of EHP Notes	—		—		(300)		—
Repayment of 2020 Senior Notes	—		—		—		(100)
Repurchases of common stock	(45)		—		(45)		—
Contribution from noncontrolling interest holders	—		—		—		2
Distributions paid to noncontrolling interest holders	(17)		(24)		(31)		(68)

Shares cancelled for taxes	—		—		—		(1)
Net cash (used in) provided by financing activities	(63)		199		(88)		43
Increase in cash	21		49		123		109
Cash—beginning of period	130		77		28		17
Cash—end of period	$	151	$	126	$	151	$	126

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

June 30, 2021

NOTE 1 BASIS OF PRESENTATION

We are an independent oil and natural gas exploration and production company operating properties exclusively within California.

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.

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, results of operations, comprehensive income, equity and cash flows for all periods presented. We have eliminated all significant intercompany transactions and accounts. We account for our share of oil and natural gas producing activities, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on our condensed consolidated financial statements.

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

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

NOTE 2 ACCOUNTING AND DISCLOSURE CHANGES

Recently Adopted Accounting and Disclosure Changes

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code. On October 13, 2020, the Bankruptcy Court confirmed our joint plan of reorganization (the Plan) and we subsequently emerged from Chapter 11 on October 27, 2020 with a new Board of Directors, new equity owners and a significantly improved financial position.

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

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

NOTE 3 OTHER INFORMATION

Other current assets — Other current assets includes the following:


	Successor
	June 30,		December 31,
	2021		2020
	(in millions)
Amounts due from joint interest partners	$	48	$	42
Receivables for premiums on derivative contracts	8		—
Prepaid expenses	19		20
Other	5		1
Other current assets	$	80	$	63

Other assets - Other assets includes the following:


	Successor
	June 30,		December 31,
	2021		2020
	(in millions)
Operating lease right-of-use assets	35		38
Deferred financing costs - Revolving Credit Facility	14		17
Emission reduction credits	11		11
Prepaid power plant maintenance	17		14
Long-term deposits and other	13		10
Other assets	$	90	$	90

Accrued liabilities — Accrued liabilities includes the following:


	Successor
	June 30,		December 31,
	2021		2020
	(in millions)
Accrued employee-related costs	$	61	$	72
Accrued taxes other than on income	31		36
Asset retirement obligations	49		50
Accrued interest	20		1
Lease liability	8		7
Fair value of derivative contracts	265		50
Deferred premiums on derivative contracts	28		18
Net settlement payments due on derivative contracts	34		3
Other	41		24
Accrued liabilities	$	537	$	261

Other long-term liabilities — Other long-term liabilities includes the following:


	Successor
	June 30,		December 31,
	2021		2020
	(in millions)
Asset retirement obligations	$	448	$	547
Deferred compensation and postretirement	181		184
Lease liability	31		35
Fair value of derivative contracts	156		6
Deferred premiums on derivative contracts	16		31
Other	18		19
Other long-term liabilities	$	850	$	822

Oil, natural gas and NGL sales — Disaggregated revenue for sales of oil, natural gas and NGLs to customers includes the following:


	Successor		Predecessor		Successor		Predecessor
	Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,
	2021		2020		2021		2020
(in millions)
Oil	$	380	$	193	$	711	$	549
Natural gas	45		26		92		64
NGLs	53		26		107		62
Oil, natural gas and NGL sales	$	478	$	245	$	910	$	675

Other expenses, net — Other expenses, net includes the following:


	Successor		Predecessor		Successor		Predecessor
	Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,
	2021		2020		2021		2020
(in millions)
Accretion expense	$	13	$	10	$	26	$	20
Severance and termination costs	1		—		15		—
Deficiency payment on a pipeline delivery contract	—		20		—		20
Other, net	9		7		12		13
Other expenses, net	$	23	$	37	53		53

Supplemental Cash Flow Information

We did not make U.S. federal and state income tax payments during the three and six months ended June 30, 2021 and 2020. Interest paid, net of capitalized amounts, totaled $2 million and $6 million for the three months ended June 30, 2021 and 2020, respectively. Interest paid, net of capitalized amounts, totaled $4 million and $51 million for the six months ended June 30, 2021 and 2020, respectively. Cash paid for reorganization items during the three and six months ended June 30, 2021 was $2 million and $4 million, respectively, for legal, professional and other fees.

Fair Value of Financial Instruments

The carrying amounts of cash and on-balance sheet financial instruments, other than debt, approximate fair value. Refer to Note 5 Debt for the fair value of our debt. Refer to Note 12 Asset Impairments for impairment charges related to our long-lived assets.

NOTE 4 INVENTORIES

Materials and supplies, which primarily consist of well equipment and tubular goods used in our oil and natural gas operations, are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods predominantly comprise produced oil and NGLs in storage, which are valued at the lower of cost or net realizable value. Inventories, by category, are as follows:


	Successor
	June 30,		December 31,
	2021		2020
	(in millions)
Materials and supplies	$	56	$	58
Finished goods	2		3
Inventories	$	58	$	61

NOTE 5 DEBT

As of June 30, 2021 and December 31, 2020, our long-term debt consisted of the following:


	Successor
	June 30,		December 31,
	2021		2020		Interest Rate	Maturity
	(in millions)

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

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

EHP Notes	—		300		6%	October 27, 2027
Senior Notes	600		—		7.125%	February 1, 2026
Principal Amount	$	600	$	599
Unamortized debt issuance costs	(11)		(2)
Long-term debt, net	$	589	$	597

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 consists of a senior revolving loan facility (Revolving Credit Facility) with an aggregate commitment of $492 million, 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 letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

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

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

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

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

•increase our capacity to make certain restricted payments, including paying dividends and repurchasing our common stock;

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

•increase our maximum hedging limitation to 85% (and permit purchased puts and floors up to 100%) of reasonably anticipated total forecasted production of crude oil, natural gas and NGLs for a 48-month period.

As of June 30, 2021, our availability under the Revolving Credit facility was as follows:


	Successor
	June 30,
	2021
	(in millions)
Borrowing capacity	$	492
Outstanding letters of credit	(125)
Availability	$	367

Senior Notes

On January 20, 2021, we completed an offering of $600 million in aggregate principal amount of our 7.125% senior unsecured notes due 2026 (Senior Notes). The net proceeds of $587 million, after $13 million of debt issuance costs, were used to repay in full our Second Lien Term Loan and EHP Notes, with the remainder used to repay substantially all of the then outstanding borrowings under our Revolving Credit Facility. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report for a description of our Second Lien Term Loan and EHP Notes. We recognized a $2 million loss on extinguishment of debt, including unamortized debt issuance costs, associated with these repayments.

Other

At June 30, 2021, we were in compliance with all financial and other debt covenants under our Revolving Credit Facility and Senior Notes.

Predecessor Note Repurchases

In the 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. Other than repaying in full our EHP Notes in January 2021, we did not repurchase or repay any notes in the second quarter of 2020 or the six months ended June 30, 2021. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report for a description of our Second Lien Notes.

Fair Value

We estimate that the fair value of our variable rate debt approximates its carrying value because the interest rate approximates current market rates. As shown in the table below, we estimated the fair value of our fixed rate Senior Notes based on observable inputs (Level 1) and the fair value of our EHP Notes with no observable inputs (Level 3).


	Successor
	June 30,		December 31,
	2021		2020
	(in millions)
Variable rate debt	$	—	$	299
Fixed rate debt

Senior Notes	633		—
EHP Notes	—		300
Fair Value of Long-Term Debt	$	633	$	599

NOTE 6 ASSETS HELD FOR SALE

In the second quarter of 2021, we entered into agreements to sell our Ventura basin operations. We expect to receive cash consideration of up to $102 million plus additional earn-out consideration that is linked to future commodity prices. The consideration includes $82 million of cash to be paid at closing and up to $20 million of potential additional consideration if the buyer does not perform certain abandonment obligations with respect to the divested properties. The additional consideration is secured by production payments of $20 million over a five-year period. To the extent the buyer satisfies all of the required abandonment obligations within a five-year period following the close date, none of the $20 million of potential additional consideration will be paid to us. The closing of the transaction is subject to customary closing conditions, including satisfaction of land and environmental due diligence and third-party consents.

The sale of our Ventura basin operations met the criteria for assets held for sale and is classified as such on our condensed consolidated balance sheet as of June 30, 2021. The amount reported as assets held for sale primarily consists of property, plant and equipment along with associated asset retirement obligations. These transactions are expected to close in the second half of 2021.

NOTE 7 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

Litigation and Claims

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

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at June 30, 2021 and December 31, 2020 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 cannot be accurately determined.

In October 2020, Signal Hill Services, Inc. defaulted on its decommissioning obligations associated with two offshore platforms. The Bureau of Safety and Environmental Enforcement (BSEE) determined that former lessees, including our former parent, Occidental Petroleum Corporation (Oxy) with a 37.5% share, are responsible for accrued decommissioning obligations associated with these offshore platforms. Oxy sold its interest in the platforms approximately 30 years ago and it is our understanding that Oxy has not had any connection to the operations since that time, and is challenging BSEE's order. Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy. We are currently evaluating this claim.

Commitment

We have a commitment of $12 million for evaluation and development activities at one of our oil and natural gas properties which is not recorded on our condensed consolidated balance sheets. In the second quarter of 2021, we entered into an amendment allowing us to accept certain land use requirements which will relieve us from our remaining obligation on or before May 2022.

NOTE 8 DERIVATIVES

We maintain a commodity hedging program primarily focused on crude oil to help protect our cash flows, margins and capital program from the volatility of commodity prices. We did not have any derivative instruments designated as accounting hedges as of and for the three and six months ended June 30, 2021 and 2020. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not accounted for as accounting hedges.

Our Revolving Credit Facility requires that we hedge a significant amount of crude oil production for a period of 36 months from the effective date of the facility. In addition, the Revolving Credit Facility requires that we maintain hedges on production for not less than two years from each quarter end.

Summary of open derivative contracts — We held the following Brent-based crude oil contracts as of June 30, 2021:


	Q3 2021		Q4 2021		Q1 2022		Q2 2022		2H 2022		2023
Sold Calls
Barrels per day	36,688		37,037		35,347		35,343		28,773		14,790
Weighted-average price per barrel	$	50.47	$	60.75	$	60.37	$	60.63	$	59.07	$	58.01





Purchased Puts
Barrels per day	36,943		35,820		35,347		35,343		28,773		14,790
Weighted-average price per barrel	$	40.18	$	40.19	$	40.57	$	41.13	$	40.70	$	40.00

Sold Puts
Barrels per day	14,647		14,193		6,869		—		2,674		—
Weighted-average price per barrel	$	30.00	$	32.00	$	32.00	$	—	$	32.00	$	—

Swaps
Barrels per day	11,063		11,922		10,869		8,669		8,386		6,930
Weighted-average price per barrel	$	51.02	$	52.61	$	52.62	$	51.31	$	51.22	$	52.15

The outcomes of the derivative positions are as follows:

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

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

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

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

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

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


June 30, 2021 (Successor)
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	(in millions)
Other current assets	$	6	$	(6)	$	—
Other assets	18		(18)		—

Liabilities
Accrued liabilities	(271)		6		(265)
Other long-term liabilities	(174)		18		(156)
	$	(421)	$	—	$	(421)


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

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

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 (loss) gain from commodity contracts on our condensed consolidated statements of operations for the three and six months ended June 30, 2021 and 2020. The changes in fair value result from the relationship between our existing positions, volatility, time to expiration, contract prices and the associated forward curves.

NOTE 9 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) was calculated using the treasury stock method for the three and six months ended June 30, 2021 and the two-class method for the three and six months ended June 30, 2020, which is required for participating securities. Certain of our restricted and performance stock unit awards outstanding during the six months ended June 30, 2020 were considered participating securities because they had non-forfeitable dividend rights at the same rate as our pre-emergence common stock. Our restricted and performance stock unit awards granted during the first half of 2021, as described in Note 13 Stock-Based Compensation, are not considered participating securities since the dividend rights on unvested shares are forfeitable.

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

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


	Successor		Predecessor		Successor		Predecessor
	Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,
	2021		2020		2021		2020
(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS
Net loss	$	(107)	$	(247)	$	(196)	$	(1,992)
Less: net income attributable to noncontrolling interests	(4)		(24)		(9)		(75)
Net loss attributable to common stock	$	(111)	$	(271)	$	(205)	$	(2,067)

Denominator for Basic and Diluted EPS
Weighted-average shares	83.1		49.5		83.2		49.4







EPS
Basic	$	(1.34)	$	(5.47)	$	(2.46)	$	(41.84)
Diluted	$	(1.34)	$	(5.47)	$	(2.46)	$	(41.84)

Weighted-average anti-dilutive shares	6.4		5.2		5.9		4.9

NOTE 10 PENSION AND POSTRETIREMENT BENEFIT PLANS

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


	Successor				Predecessor
	Three months ended June 30,				Three months ended June 30,
	2021				2020
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
(in millions)
Service cost	$	1	$	1	$	1	$	1
Interest cost	—		1		—		1
Expected return on plan assets	(1)		—		—		—


Total	$	—	$	2	$	1	$	2


	Successor				Predecessor
	Six months ended June 30,				Six months ended June 30,
	2021				2020
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
(in millions)
Service cost	$	1	$	2	$	1	$	2
Interest cost	—		2		1		2
Expected return on plan assets	(1)		—		—		—


Total	$	—	$	4	$	2	$	4

We contributed $1 million to our defined benefit plans during the three and six months ended June 30, 2021. We expect to satisfy our minimum funding requirements with contributions of approximately $3 million to our defined benefit pension plans during the remainder of 2021.

We did not make significant contributions to our defined benefit pension plans for the three and six months ended June 30, 2020. The Coronavirus Aid, Relief, and Economic Security 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. During 2020, we deferred contributions to our defined benefit pension plans of approximately $5 million, which we funded in December 2020.

NOTE 11 INCOME TAXES

We estimate our annual effective income tax rate to record our quarterly income tax provision in the jurisdictions in which we operate. Statutory tax rate changes and other significant or unusual items, if any, are not included in our annual effective income tax rate and are instead recognized as discrete items in the quarter in which they occur.

For the six months ended June 30, 2021 and 2020, we did not provide any current or deferred income tax provision or benefit. The difference between our statutory tax rate and our effective tax rate of 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 sustained level of profitability that we can achieve.

NOTE 12 ASSET IMPAIRMENTS

The following table presents a summary of our asset impairments:


	Successor		Predecessor
	Six months ended June 30,		Six months ended June 30,
	2021		2020
(in millions)
Proved oil and natural gas properties	$	—	$	1,487
Unproved properties	—		228
Other	3		21
Total	$	3	$	1,736

We recognized a $3 million impairment charge during the six months ended June 30, 2021 which was triggered by the change in our business strategy and capital allocation priorities resulting in the abandonment of certain capital projects.

During the six months ended June 30, 2020, we recorded a $1.7 billion impairment which was triggered by the sharp drop in commodity prices at the end of the first quarter of 2020. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 13 Asset Impairment in our 2020 Annual Report for a description of our impairment of proved and unproved oil and gas properties and other asset impairments during the six months ended June 30, 2020.

NOTE 13 STOCK-BASED COMPENSATION

The California Resources Corporation 2021 Long Term Incentive Plan (Long Term Incentive Plan) provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, vested stock awards, dividend equivalents, other stock-based awards and substitute awards to employees, officers, non-employee directors and other service providers of the Company and its affiliates. The Long Term Incentive Plan replaces the earlier Amended and Restated California Resources Corporation Long Term Incentive Plan which was cancelled upon our emergence from bankruptcy, along with all outstanding stock-based compensation awards granted thereunder.

Shares of our common stock may be withheld by us in satisfaction of tax withholding obligations arising upon the vesting of restricted stock units (RSUs) and performance stock units (PSUs).

Stock-based compensation expense is primarily recorded in general and administrative expenses on our condensed consolidated statements of operations based on job function of the employees receiving the grants as shown in the table below. Stock-based compensation reported as a component of operating costs is not significant for all periods presented.


	Successor		Predecessor		Successor		Predecessor
	Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,
	2021		2020		2021		2020
(in millions)
General and administrative expenses	$	4	$	1	$	6	$	2

For the three and six months ended June 30, 2021 and 2020, we did not recognize any income tax benefit related to our stock-based compensation. For the three and six months ended June 30, 2020, we made cash payments of $7 million and $15 million, for the cash-settled portion of our pre-emergence awards, respectively.

Restricted Stock Units

Executives and non-employee directors were granted RSUs during the first half of 2021 which are in the form of, or equivalent in value to, actual shares of our common stock. The awards generally vest ratably over three years, with one third of the granted units vesting on each of the first three anniversaries of the applicable date of grant. RSUs are settled in shares of our common stock at the end of the third year of the three-year vesting period.

The following table sets forth RSU activity for the six months ended June 30, 2021:



	Number of Units	Weighted-Average Grant-Date Fair Value
	(in thousands)
Unvested at December 31, 2020 (Successor)	—	$	—
Granted	1,180	$	24.74
Cancelled or Forfeited	(36)	$	24.50
Unvested at June 30, 2021 (Successor)	1,144

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

As of June 30, 2021, the unrecognized compensation expense for all of our unvested RSUs was approximately $25 million and is expected to be recognized over a weighted-average period of approximately three years.

Performance Stock Units

Executives were granted PSUs during the first half of 2021 which contained a market condition. PSUs are earned upon the attainment of specified 60-trading day volume weighted average prices for shares of our common stock generally during a three-year service period commencing on the grant date. Once units are earned, the earned units are not reduced for subsequent decreases in stock price. For the duration of the three-year period, a minimum of 0% and a maximum of 100% of the PSUs granted could be earned. Earned PSUs generally vest on the third anniversary of the grant date and are settled in shares of our common stock at that time.

The following table sets forth PSU activity for the six months ended June 30, 2021:



	Number of Units	Weighted-Average Grant-Date Fair Value
	(in thousands)
Unvested at December 31, 2020 (Successor)	—	$	—
Granted	969	$	19.72
Cancelled or Forfeited	(21)	$	19.31
Unvested at June 30, 2021 (Successor)	948

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

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


	Second Quarter		First Quarter
	2021		2021


Expected volatility(a)	60.00% - 65.00%		65.00	%
Risk-free interest rate(b)	0.16% - 0.17%		0.17% - 0.32%
Dividend yield	—	%	—	%
Forecast period (in years)	2 - 3		3

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

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

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

As of June 30, 2021, the unrecognized compensation expense for all of our unvested PSUs was approximately $17 million and is expected to be recognized over a weighted-average period of approximately three years.

NOTE 14 EQUITY

In May 2021, our Board of Directors authorized a Share Repurchase Program to acquire up to $150 million of our common stock through March 31, 2022. See Note 15 Subsequent Events for more information on an increase to our Share Repurchase Program. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time.

As of June 30, 2021, we repurchased 1.4 million shares of our common stock, at an average price of $31.56 per share, through either open market purchases or a Rule 10b5-1 plan at an aggregate cost of $45 million. Shares repurchased were held as treasury stock as of June 30, 2021.

NOTE 15 SUBSEQUENT EVENTS

Acquisitions

In April 2017, we entered into a development joint venture with Macquarie Infrastructure and Real Assets Inc. (MIRA) to develop certain of our oil and natural gas properties in the San Joaquin basin in exchange for a 90% working interest in the related properties. In August 2021, we purchased MIRA’s entire working interest share in the conveyed assets for $53 million, before transaction costs. Prior to the acquisition, our consolidated results reflect only our 10% working interest share in the productive wells.

Share Repurchase Program

In August 2021, our Board of Directors authorized an increase to the Share Repurchase Program of $100 million to $250 million of our common stock through March 31, 2022.

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

General

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

We qualified for and adopted fresh start accounting upon emergence from bankruptcy on October 27, 2020, at which point we became a new entity for financial reporting purposes. We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start accounting and the effects of the implementation of our joint plan of reorganization (the Plan), the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.

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

Business Environment and Industry Outlook

Commodity Prices

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

Global oil prices were higher in the three and six months ended June 30, 2021 compared to the same periods in 2020. Benchmark prices for Brent crude oil in the first half of 2021 increased 55% from the same period in 2020 demonstrating a strong recovery from the same prior year period when oil prices were negatively influenced by the Coronavirus Disease 2019 (COVID-19) pandemic and by the actions of foreign producers. Commodity prices have benefited from rising consumption and economic growth due to the lifting of restrictions related to the COVID-19 pandemic. During the first half of 2021, members of Organization of Petroleum Exporting Countries (OPEC) continued to restrain crude oil production attempting to reduce oil supplies built during 2020.

The following table presents the average daily Brent, WTI and NYMEX prices for the three and six months ended June 30, 2021 and 2020:



	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Brent oil ($/Bbl)	$	69.02	$	33.27	$	65.06	$	42.12
WTI oil ($/Bbl)	$	66.07	$	27.85	$	61.96	$	37.01
NYMEX gas ($/MMBtu)	$	2.76	$	1.77	$	2.74	$	1.91

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

See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Production and Prices and Part II, Item 1A – Risk Factors in our 2020 Annual Report for further discussion regarding the impact of the pandemic and declines in commodity prices.

Production

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


	Successor	Predecessor	Successor	Predecessor
	Three months ended June 30,	Three months ended June 30,	Six months ended June 30,	Six months ended June 30,
	2021	2020	2021	2020
Oil (MBbl/d)
San Joaquin Basin	39	41	38	44
Los Angeles Basin	19	27	20	26
Ventura Basin	3	2	2	3

Total	61	70	60	73
NGLs (MBbl/d)
San Joaquin Basin	13	13	12	14

Ventura Basin	—	—	1	—

Total	13	13	13	14
Natural gas (MMcf/d)
San Joaquin Basin	135	148	135	151
Los Angeles Basin	1	2	1	2
Ventura Basin	5	3	5	4
Sacramento Basin	20	21	20	22
Total	161	174	161	179

Total Net Production (MBoe/d)	101	112	100	117

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.

Total daily production for the three months ended June 30, 2021, compared to the same period in 2020, decreased by approximately 11 MBoe/d or 10%. The decrease in production largely resulted from limited drilling activity and capital investment during the prior 12 months and natural decline rates. Our production-sharing contracts (PSCs), as described below, negatively impacted our oil production in the second quarter of 2021 by approximately five MBoe/d compared to the same period in 2020. Our total daily production for the three months ended June 30, 2021 decreased by approximately 5% compared to the same period in 2020 after excluding the impact of PSC-type contracts.

For the six months ended June 30, 2021 compared to the same period in 2020, total daily production decreased by approximately 17 MBoe/d or 15%. The decrease in production largely resulted from limited drilling activity and capital investment during the prior 12 months and natural decline. Production volumes were also negatively impacted by downtime at one of our gas processing plants and our PSC-type contracts. Our total daily production decreased by 12 MBoe/d or 10% compared to the same period in 2020 after excluding the impact of PSC-type contracts and unscheduled downtime.

Production-Sharing Contracts (PSCs)

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of production and reserves to recover a portion of such capital and operating costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and operating costs that we incur on their behalf, (ii) for our share of contractually defined base production and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and operating costs. However, our net economic benefit is greater when product prices are higher. These contracts represented approximately 15% of our net production for the three months ended June 30, 2021.

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

The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. See Statements of Operations Analysis, Results of Oil and Gas Operations below for our operating costs and operating costs, excluding the effects of our PSC-type contracts on a per Boe basis.

Prices and Realizations

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


	Successor			Predecessor
	Three months ended June 30,			Three months ended June 30,
	2021			2020
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	69.02		$	33.27

Realized price without hedge	$	68.94	100%	$	30.27	91%
Settled hedges	(14.84)			0.55
Realized price with hedge	$	54.10	78%	$	30.82	93%

WTI	$	66.07		$	27.85

Realized price without hedge	$	68.94	104%	$	30.27	109%
Realized price with hedge	$	54.10	82%	$	30.82	111%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	44.90	65%	$	21.05	63%
Realized price (% of WTI)	$	44.90	68%	$	21.05	76%

Natural gas
NYMEX ($/MMBtu)	$	2.76		$	1.77

Realized price without hedge ($/Mcf)	$	3.04	110%	$	1.65	93%
Settled hedges	(0.01)			0.08
Realized price with hedge ($/Mcf)	$	3.03	110%	$	1.73	98%


	Successor			Predecessor
	Six months ended June 30,			Six months ended June 30,
	2021			2020
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	65.06		$	42.12

Realized price without hedge	$	64.89	100%	$	41.02	97%
Settled hedges	(10.98)			2.74
Realized price with hedge	$	53.91	83%	$	43.76	104%

WTI	$	61.96		$	37.01

Realized price without hedge	$	64.89	105%	$	41.02	111%
Realized price with hedge	$	53.91	87%	$	43.76	118%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	46.75	72%	$	25.18	60%
Realized price (% of WTI)	$	46.75	75%	$	25.18	68%

Natural gas
NYMEX ($/MMBtu)	$	2.74		$	1.91

Realized price without hedge ($/Mcf)	$	3.17	116%	$	1.96	103%
Settled hedges	(0.03)			0.09
Realized price with hedge ($/Mcf)	$	3.14	115%	$	2.05	107%

Oil — Brent index and realized prices excluding hedge settlements were higher in the three and six month periods ended June 30, 2021 compared to the same periods in 2020 as oil demand recovered from its COVID-19 driven lows. Prices collapsed in March 2020 at the beginning of the pandemic and have since improved as a result of easing mobility restrictions and the delayed effects of pandemic-related production curtailments and reduced capital investments by OPEC members, domestic producers and Russia.

NGLs — Prices for NGLs increased for the three and six month periods ended June 30, 2021 compared to the same periods in 2020. In 2020, demand declined at the onset of COVID-19 that caused materially lower NGL prices and resulted in production curtailments. Production curtailments continued into 2021 causing tighter supplies and higher benchmark prices in the face of improving demand.

Natural Gas — Natural gas index and realized prices were higher in the three and six months ended June 30, 2021 compared to the same periods in 2020. The pandemic caused natural gas demand to decline which prompted producers to, in response, reduce production and investment. As pandemic-related mobility restrictions have been lifted, production increases have thus far failed to keep pace with prompt demand and seasonal storage requirements.

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 six months ended June 30, 2021 and 2020:


	Successor		Predecessor		Successor		Predecessor
	Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,
	2021		2020		2021		2020
Energy operating costs(a)	$	4.70	$	3.51	$	4.70	$	3.61
Gas processing costs	0.66		0.46		$	0.60	$	0.57
Non-energy operating costs(b)	13.12		8.45		$	13.10	$	10.81
Operating costs	$	18.48	$	12.42	$	18.40	$	14.99

Operating costs, excluding effects of PSC-type contracts(c)	$	16.75	$	12.00	$	16.74	$	14.33
Field general and administrative expenses(d)	$	0.77	$	1.17	$	0.83	$	1.08
Field depreciation, depletion and amortization(d)(e)	$	5.36	$	7.82	$	5.25	$	8.98
Field taxes other than on income	$	2.95	$	2.84	$	3.21	$	2.96

(a)Energy operating costs consist of purchases of fuel gas used to generate electricity, purchased electricity and internal costs to produce electricity used in our operations.

(b)Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. Purchases of fuel gas to generate steam which is then used in our steamfloods is included in non-energy operating costs.

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

(d)Excludes corporate expenses. Field general and administrative expenses decreased for the three and six months ended June 30, 2021 from the same period in 2020 primarily due to workforce reductions in the second half of 2020 and the first quarter of 2021.

(e)Field depreciation, depletion and amortization decreased in the three and six months ended June 30, 2021 from the same period in 2020 primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the fresh start valuation of our property, plant and equipment.

Consolidated Results of Operations

The following table presents our consolidated results of operations for the three and six months ended June 30, 2021 and 2020:


	Successor		Predecessor		Successor		Predecessor
	Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,
	2021		2020		2021		2020
(in millions)
Oil, natural gas and NGL sales	$	478	$	245	$	910	$	675
Net derivative (loss) gain from commodity contracts	(265)		(4)		(478)		75
Trading revenue	48		14		146		59
Electricity sales	33		19		66		32
Other revenue	10		2		23		8
Operating costs	(169)		(127)		(333)		(319)
General and administrative expenses	(48)		(69)		(96)		(129)
Depreciation, depletion and amortization	(54)		(88)		(106)		(207)
Asset impairments	—		—		(3)		(1,736)
Taxes other than on income	(37)		(38)		(77)		(79)
Exploration expense	(2)		(2)		(4)		(7)
Trading costs	(30)		(8)		(91)		(32)
Electricity cost of sales	(17)		(14)		(41)		(30)
Transportation costs	(14)		(8)		(26)		(21)
Other expenses, net	(23)		(37)		(53)		(53)
Reorganization items	(2)		—		(4)		—
Interest and debt expense, net	(13)		(85)		(26)		(172)
Net gain on early extinguishment of debt	—		—		(2)		5
Gain on asset divestitures	—		—		—		—
Other non-operating expenses	(2)		(47)		(1)		(61)
Loss before income taxes	(107)		(247)		(196)		(1,992)
Income tax	—		—		—		—
Net loss	(107)		(247)		(196)		(1,992)
Net income attributable to noncontrolling interests	(4)		(24)		(9)		(75)
Net loss attributable to common stock	$	(111)	$	(271)	$	(205)	$	(2,067)

Three months ended June 30, 2021 vs. 2020

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the impact of settled hedges, were $478 million for the three months ended June 30, 2021, which is an increase of $233 million compared to $245 million for the same period of 2020. The increase was due to higher realized prices, which was partially offset by lower production, as reflected in the following table:


	Oil		NGLs		Natural Gas		Total
	(in millions)
Three months ended June 30, 2020	$	193	$	26	$	26	$	245
Changes in realized prices	246		29		22		297
Changes in production	(59)		(2)		(3)		(64)
Three months ended June 30, 2021	$	380	$	53	$	45	$	478

Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

The effect of settled hedges is not included in the table above. Payments for settled hedges were $82 million for the three months ended June 30, 2021 compared to proceeds of $5 million for the same period of 2020. Including the effect of settled hedges, our oil, natural gas and NGL revenue increased by $146 million or 58% compared to the same prior-year period.

Net derivative loss from commodity contracts — Net derivative loss from commodity contracts was $265 million for the three months ended June 30, 2021 compared to a net loss of $4 million in the same period of 2020. The 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 and the associated forward curves.


	Three months ended June 30,		Three months ended June 30,
	2021		2020
(in millions)
Non-cash derivative loss, excluding noncontrolling interest	$	(183)	$	—
Non-cash derivative loss, noncontrolling interest	—		(9)
Total non-cash changes	(183)		(9)
Net (payments) proceeds on settled commodity derivatives	(82)		5

Net derivative loss from commodity contracts	$	(265)	$	(4)

Trading revenue — Trading revenue was $48 million for the three months ended June 30, 2021, an increase of $34 million, or 243% from $14 million during the same period of 2020. The increase was predominantly the result of higher volume and prices related to our natural gas trading activities created by a warmer summer in 2021 as compared to 2020. Our net margin from natural gas trading activities, after deducting the cost of related natural gas purchases, was $18 million for the three months ended June 30, 2021 compared to $6 million for the same period of 2020.

Electricity sales — Electricity sales increased $14 million to $33 million in the second quarter of 2021 compared to $19 million in the same period of 2020. The increase was predominantly due to higher electricity prices in 2021 resulting from higher natural gas prices as well as reduced hydroelectric generation in California. Volumes sold in the second quarter of 2020 were lower than the second quarter of 2021 due to planned maintenance at the Elk Hills power plant in the first quarter of 2021 which continued in the early part of April 2020.

Operating costs — Operating costs for the three months ended June 30, 2021 were $169 million, which was an increase of $42 million or 33% from $127 million for the same period of 2020. The increase was primarily attributable to higher downhole maintenance activity in 2021 which was deferred in 2020 as we shut-in wells. Additionally, operating costs increased in 2021 due to higher energy costs and natural gas prices as compared to 2020. Partially offsetting these increases were lower compensation-related costs from streamlining our operations, which included headcount reductions in late 2020 and early 2021 as well as benefit reductions in the second quarter of 2021. Our second quarter 2020 results reflect cost savings for reduced work hours and reduced management salaries in response to the industry downturn resulting from the COVID-19 pandemic. Although higher natural gas and electricity prices in 2021 increased our operating costs, higher prices have a net positive effect on our operating results due to higher revenue from sales of these commodities which we also produce.

General and administrative expenses — Our general and administrative (G&A) expenses were $48 million for the three months ended June 30, 2021, which was a decrease of $21 million from $69 million for the three months ended June 30, 2020. The decrease in G&A expenses reflects lower compensation-related costs primarily due to workforce reductions that occurred in the second half of 2020 and the first quarter of 2021 as well as benefit reductions in the second quarter of 2021. Our second quarter 2020 results include cost savings from reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic. The remaining decrease between comparative periods was primarily due to cost saving efforts which resulted in lower spend across a number of cost categories. The decrease was partially offset by stock-based compensation expense related to awards granted to executives and directors in 2021.

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $34 million to $54 million in the second quarter of 2021 compared to $88 million in the same period of 2020 was primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the valuation of our property, plant and equipment.

Trading costs — Natural gas purchases related to trading activities were $30 million for the three months ended June 30, 2021, which was an increase of $22 million or 275% from $8 million for the same period in 2020. The change was predominantly the result of higher activity levels and prices.

Other expenses, net — Other expenses, net was $23 million for the three months ended June 30, 2021, which was a decrease of $14 million from $37 million during the same period of 2020. The decrease was largely due to a one-time payment of $20 million made in connection with an expiring pipeline delivery contract partially offset by a $3 million property tax refund.

Interest and debt expense, net — Interest and debt expense, net decreased $72 million to $13 million in the second quarter of 2021 compared to $85 million in the same period of 2020 primarily due to a decrease in our overall level of debt following our emergence from bankruptcy. Additionally, we reduced the amount drawn on our Revolving Credit Facility and had no balance drawn during the quarter. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 8 Debt in our 2020 Annual Report for additional information on the terms of the Plan, our emergence from bankruptcy and our long-term debt transactions.

Other non-operating expense — Other non-operating expense decreased $45 million to $2 million for the three months ended June 30, 2021 compared to $47 million in the same period for 2020. The decrease primarily due to the significant legal, professional and other fees incurred in preparation for our Chapter 11 filing on July 15, 2020.

Net income attributable to noncontrolling interests — Upon emergence from bankruptcy, we acquired all of

ECR's member interests in the Ares JV; therefore, the allocation of net income to noncontrolling interest

holders in the Successor period for the three months ended June 30, 2021 is lower than the Predecessor period for the three months ended June 30, 2020. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report for additional information on the settlement terms of the Ares JV.

Six Months Ended June 30, 2021 vs. 2020

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the impact of settled hedges, were $910 million for the six months ended June 30, 2021, which is an increase of $235 million compared to $675 million for the same period of 2020. The increase was due to higher realized prices, which was partially offset by lower production, as reflected in the following table:


	Oil		NGLs		Natural Gas		Total
	(in millions)
Six months ended June 30, 2020	$	549	$	62	$	64	$	675
Changes in realized prices	319		53		39		411
Changes in production	(157)		(8)		(11)		(176)
Six months ended June 30, 2021	$	711	$	107	$	92	$	910

Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

The effect of settled hedges is not included in the table above. Payments for settled hedges were $121 million for the six months ended June 30, 2021 compared to proceeds of $103 million, including $63 million of proceeds from derivative contracts sold prior to maturity, in the first quarter of 2020. Including the effect of settled hedges, our oil, natural gas and NGL revenue increased by $11 million or 1% compared to the same prior-year period.

Net derivative loss from commodity contracts — Net derivative loss from commodity contracts was $478 million for the six months ended June 30, 2021 compared to a net gain of $75 million in the same period of 2020. The 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 and the associated forward curves.


	Six months ended June 30,		Six months ended June 30,
	2021		2020
(in millions)
Non-cash derivative loss, excluding noncontrolling interest	(357)		$	(35)
Non-cash derivative gain, noncontrolling interest	—		7
Total non-cash changes	(357)		(28)
Net (payments) proceeds on settled commodity derivatives	(121)		40
Net proceeds on derivative contracts sold prior to maturity	—		63
Net derivative (loss) gain from commodity contracts	$	(478)	$	75

Trading revenue — Trading revenue was $146 million for the six months ended June 30, 2021, an increase of $87 million, or 147% from $59 million during the same period of 2020. The increase was predominantly the result of higher volume and prices related to our natural gas trading activities created by colder winter temperatures and a warmer summer in 2021 as compared to 2020. Our net margin from natural gas trading activities, after deducting the cost of related natural gas purchases, was $55 million for the six months ended June 30, 2021 compared to $27 million for the same period of 2020.

Electricity sales — Electricity sales increased $34 million to $66 million in the first half of 2021 compared to $32 million in the same period of 2020. Electricity sales increased in the first half of 2021 from the prior year period as a result of higher pricing resulting from reduced hydroelectric generation in California as well as increased natural gas prices. In the first half of 2020, sales volumes were also lower from planned maintenance and an outage at the Elk Hills power plant.

Operating costs — Operating costs for the six months ended June 30, 2021 were $333 million, which was an increase of $14 million or 4% from $319 million for the same period of 2020. The increase was primarily attributable to higher downhole maintenance activity in 2021 which was deferred in 2020 as we shut-in wells. Additionally, operating costs increased in 2021 due to higher energy costs and natural gas prices as compared to 2020. These increases were partially offset by lower compensation-related costs from streamlining our operations, including headcount reductions in the second half of 2020 and in the first quarter of 2021 as well as benefit reductions in the second quarter of 2021. Although higher natural gas and electricity prices increase our operating costs, higher prices have a net positive effect on our operating results due to higher revenue from sales of these commodities which we also produce.

General and administrative expenses — Our general and administrative (G&A) expenses were $96 million for the six months ended June 30, 2021, which was a decrease of $33 million from $129 million for the six months ended June 30, 2020. The decrease in G&A expenses were primarily attributable to lower compensation-related costs as a result of workforce reductions that occurred in the second half of 2020 and the first quarter of 2021 as well as benefit reductions in the second quarter of 2021. The remaining decrease was primarily due to cost savings efforts which resulted in lower spend across a number of cost categories. The decrease was partially offset by stock-based compensation expense related to awards granted to executives and directors in 2021.

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $101 million to $106 million in the first half of 2021 compared to $207 million in the same period of 2020 was primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the valuation of our property, plant and equipment.

Asset impairments — Asset impairment charges for the six months ended June 30, 2021 were $3 million for the impairment of capitalized costs related to projects which were abandoned. For the same period in 2020, we recorded an impairment charge of $1.7 billion due to the sharp drop in commodity prices in March 2020, which included $1.5 billion related to certain of our proved properties and approximately $228 million related to unproved acreage that was no longer included in our development plans at that time. See Part I, Item 1 – Financial Statements, Note 12 Asset Impairments for additional information.

Trading costs — Natural gas purchases related to trading activities were $91 million for the six months ended June 30, 2021, which was an increase of $59 million or 184% from $32 million for the same period in 2020. The change was predominantly the result of higher activity levels and prices related to natural gas trading activities.

Electricity cost of sales — Electricity cost of sales increased from $30 million in the first half of 2020 to $41 million in the same period of 2021. The increase was primarily a result of higher pricing on natural gas purchases.

Interest and debt expense, net — Interest and debt expense, net decreased $146 million to $26 million in the first half of 2021 compared to $172 million in the same period of 2020 primarily due to a decrease in our overall level of debt upon our emergence from bankruptcy. Additionally, in the first quarter of 2021, we reduced the amount drawn on our Revolving Credit Facility and had no balance drawn in the second quarter. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 8 Debt in our 2020 Annual Report for additional information on the terms of the Plan, our emergence from bankruptcy and our long-term debt transactions.

Other non-operating expense — Other non-operating expense decreased $60 million to $1 million for the six months ended June 30, 2021 compared to $61 million in the same period for 2020. The higher expense in the first half of 2020 was primarily a result of legal, professional and other fees related to our bankruptcy filing and an abandoned financing transaction.

Net income attributable to noncontrolling interests — Upon emergence from bankruptcy, we acquired all of

ECR's member interests in the Ares JV; therefore, the allocation of net income to noncontrolling interest

holders in the Successor period for the six months ended June 30, 2021 is lower than the Predecessor period for the six months ended June 30, 2020. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report for additional information on the settlement terms of the Ares JV.

Liquidity and Capital Resources

Cash Flow Analysis

Cash flows from operating activities — Our net cash provided by (used in) 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. For the three months ended June 30, 2021, our operating cash flow increased 194%, or $262 million, to $127 million from $(135) million in the same prior period of 2020. For the six months ended June 30, 2021, our operating cash flow increased 195%, or $181 million, to $274 million from $93 million in the same period of 2020.

The increase in operating cash flow primarily relates to higher average realized prices with hedge settlements in 2021 compared to the same prior-year period which is primarily due to the economic recovery in 2021 as COVID-19 driven mobility restrictions were lifted and demand increased. This increase was partially offset by lower production volumes in 2021 as compared to the same periods in 2020. Changes in operating assets and liabilities in the three months ended June 30, 2021 decreased our operating cash flow by $25 million compared to an increase of $17 million in the comparable period of 2020. Changes in operating assets and liabilities in the six months ended June 30, 2021 decreased our operating cash flow by $25 million compared to an increase of $130 million in the comparable six months of 2020. These working capital changes were largely a result of higher trade accounts receivable balances as well as higher payables related to derivatives and increased activity.

Cash flows from investing activities — Our net cash used in investing activities increased $28 million, or 187% from $15 million for the three months ended June 30, 2020 to $43 million for the same period in 2021. Our net cash used in investing activities increased $36 million, or 133% from $27 million for the six months ended June 30, 2020 to $63 million for the same period in 2021. The table below summarizes net cash used in investing activities for the three and six months ended June 30, 2021 and 2020 (in millions):


	Successor		Predecessor		Successor		Predecessor
	Three months ended June 30, 2021		Three Months Ended June 30, 2020		Six months ended June 30, 2021		Six Months Ended June 30, 2020
(in millions)
Capital investments	$	(50)	$	(3)	$	(77)	$	(33)
Changes in capital investment accruals	8		(9)		13		(28)
Proceeds from divestitures	—		—		2		41
Other	(1)		(3)		(1)		(7)
Net cash used in investing activities	$	(43)	$	(15)	$	(63)	$	(27)

Cash flows from financing activities — Our net cash used in financing activities was $63 million for the three months ended June 30, 2021 compared to net cash provided by financing activities of $199 million or the same period of 2020. Our net cash used in financing activities was $88 million for the six months ended June 30, 2021 compared to net cash provided by financing activities of $43 million for the same period of 2020. Financing activities for the three months ended June 30, 2021 included repurchases of 1.4 million shares of common stock at an aggregate cost of $45 million under our Share Repurchase Program. Financing activities for the three and six months ended June 30, 2020 primarily included net borrowings under our revolving credit facility in place at that time. The table below summarizes net cash used by financing activities for the three and six months ended June 30, 2021 and 2020 (in millions):


	Successor		Predecessor		Successor		Predecessor
	Three months ended June 30, 2021		Three Months Ended June 30, 2020		Six months ended June 30, 2021		Six Months Ended June 30, 2020
(in millions)
Debt transactions, net	$	(1)	$	223	$	(12)	$	113
Debt repurchases	—		—		—		(3)
Distributions to noncontrolling interest holders, net	(17)		(24)		(31)		(66)
Repurchases of common stock	(45)		—		(45)		—
Other	—		—		—		(1)
Net cash (used in) provided by financing activities	$	(63)	$	199	$	(88)	$	43

Liquidity

Our primary sources of liquidity and capital resources are cash flows from operations, cash on hand and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the first half of 2021 was for capital investment, distributions to a noncontrolling interest holder and repurchases of our common stock.

At current commodity prices and our planned 2021 capital program described below, we expect to generate positive free cash flow, which we may use (i) to increase investments in our drilling program to accelerate value, (ii) to pay dividends or buy back stock to the extent permitted under our Revolving Credit Facility and Senior Notes indenture, (iii) to maintain cash on our balance sheet, or (iv) for other corporate purposes. We may begin paying income taxes in early 2022 if Brent prices remain at current levels for a sustained period. Our tax paying status depends on a number of factors, including but not limited to, the amount and type of our capital spend, cost structure and activity levels. Potential legislation could also limit tax incentives for fossil fuels. We believe we have sufficient sources of cash to meet our obligations for the next twelve months.

The following table summarizes our liquidity (in millions):


	Successor
	June 30,
	2021
	(in millions)
Cash	$	151
Revolving Credit Facility:
Borrowing capacity(a)	492
Outstanding letters of credit	(125)
Availability	$	367

Liquidity	$	518

(a)In April 2021, the aggregate commitment of our lenders was reduced to $492 million based on the terms of our Revolving Credit Facility. See Part I, Item 1 – Financial Statements, Note 5 Debt for more information on our Revolving Credit Facility.

Amendment to Revolving Credit Facility

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

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

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

•increase our capacity to make certain restricted payments, including paying dividends and repurchasing our common stock;

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.

Our Revolving Credit Facility requires us to maintain hedges on a minimum amount of crude oil production, determined semi-annually, of no less than (i) 75% of our reasonably anticipated oil production from our proved reserves for the first 24 months after the closing of the Revolving Credit Facility on October 27, 2020, and (ii) 50% of our reasonably anticipated oil production from our proved reserves for a period from the 25th month through the 36th month after the same date. The Revolving Credit Facility specifies the forms of hedges and prices (which can be prevailing prices) that must be used for a portion of those hedges.

Our Revolving Credit Facility also requires us to maintain acceptable commodity hedges for no less than 50% of the reasonably anticipated oil production from our proved reserves for at least 24 months following the date of delivery of each reserve report if our leverage ratio is greater than 2.00:1.00. If our leverage ratio is less than 2.00:1.00, then the minimum amount of hedges that we are required to maintain is reduced from 50% to 33%. Currently, we may not hedge more than 85% of reasonably anticipated total forecasted production of crude oil, natural gas and NGLs from our oil and gas properties for a 48-month period, except that we may purchase puts and floors up to 100% of such production.

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. We did not have any commodity derivatives designated as accounting hedges as of and during the three or six months ended June 30, 2021.

See Part I, Item 1 – Financial Statements, Note 8 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of June 30, 2021.

2021 Capital Program

Our capital program will be dynamic in response to oil market volatility while focusing on maintaining our oil production and strong liquidity and maximizing our free cash flow. We entered 2021 with an internally funded capital program of $200 million to $225 million. We have since reduced the full year 2021 capital program to $170 million to $190 million reflecting a reallocation of drilling capital to downhole maintenance activities which provide efficiencies and faster payouts. The current capital program anticipates that we will maintain a consistent level of investment throughout the remainder of the year. If commodity prices decline significantly from current levels, we may need to decrease the size of our capital program in response to market conditions.

Any 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.

The amounts in the table below reflect components of our capital investment for the periods indicated, excluding changes in capital investment accruals (in millions):


	Successor
	2021 Full Year Estimate	Six months ended June 30, 2021
	(in millions)
Drilling	$90 - $100	$41
Capital workovers	35 - 40	17
Infrastructure, corporate and other	45 - 50	19
Total	$170 - $190	$77

Regulatory Update

In April 2021, Governor Gavin Newsom signed an executive order directing the California Department of Conservation’s Geologic Energy Management Division to initiate a rulemaking to end the issuance of new permits for well stimulation treatments by January 1, 2024 and instructed the California Air Resources Board to evaluate methods of phasing out oil extraction across the state by 2045. In May 2021, the Division published the proposed rule to end the issuance of new permits for well stimulation treatments. We expect little to no impact on future development activities because we are not dependent on well stimulation treatments. Less than 1% of our proved reserves require well stimulation and our current long-term development plans do not include well stimulation.

Share Repurchase Program

In August 2021, our Board of Directors authorized an increase to the Share Repurchase Program by $100 million to $250 million through March 31, 2022.

Divestitures

In the second quarter of 2021, we entered into agreements to sell our Ventura basin operations. We expect to receive cash consideration of up to $102 million plus additional earn-out consideration that is linked to future commodity prices. The consideration includes $82 million of cash to be paid at closing and up to $20 million of potential additional consideration if the buyer does not perform certain abandonment obligations with respect to the divested properties. The additional consideration is secured by production payments of $20 million over a five-year period. To the extent the buyer satisfies all of the required abandonment obligations within a five-year period following the close date, none of the $20 million of potential additional consideration will be paid to us. The amount of the earn-out consideration actually received is not yet certain, but assuming an average oil price of approximately $80 per barrel during the twelve months following closing, would approximate $8 million and would generally be received in quarterly installments. The closing of the transaction is subject to customary closing considerations, including satisfaction of land and environmental due diligence and third-party consents.

Acquisitions and Joint Ventures

In February 2017, we entered into a development joint venture (JV) with Benefit Street Partners (BSP) to develop certain oil and natural gas assets in exchange for a preferred interest in the BSP JV. BSP invested $200 million and is entitled to preferred distributions and, if it receives cash distributions equal to a predetermined threshold, the preferred interest is automatically redeemed in full with no additional payment. For the first half of 2021, we distributed $31 million to BSP. We anticipate our remaining distributions to BSP in the second half of 2021 will approximate $20 million. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report for additional information on our BSP JV.

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.

Fixed and Variable Costs

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

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.

See Part I, Item 1 – Financial Statements, Note 7 Lawsuits, Claims, Commitments and Contingencies for further information.

Significant Accounting and Disclosure Changes

See Part I, Item 1 – Financial Statements, Note 2 Accounting and Disclosure Changes for a discussion of new accounting matters.

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

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

•budgets and maintenance capital requirements

•reserves and reservoir characteristics

•type curves

•expected synergies from acquisitions and joint ventures

•energy transition initiatives

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 natural gas liquids 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, interest payments on our debt, 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;

•legislative or regulatory changes, including those related to (i) drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, (ii) managing energy, water, land, greenhouse gases (GHGs) or other emissions, (iii) protection of health, safety and the environment, (iv) tax credits or other incentives, or (v) 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;

•production-sharing contracts’ effects on production and unit operating costs;

•the effect of our 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 COVID-19; and

•our ability to realize the benefits of business strategies and initiatives related to energy transition, including carbon capture and sequestration projects and other renewable energy efforts;

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

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.

Item 3Quantitative and Qualitative Disclosures About Market Risk

For the three and six months ended June 30, 2021, there were no material changes to market risks from the information provided under Item 305 of Regulation S-K included under the caption Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk in the 2020 Annual Report, except as discussed below.

Commodity Price Risk

Our financial results are sensitive to fluctuations in oil, NGL and natural gas 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. The primary market risk relating to our derivative contracts relates to fluctuations in market prices as compared to the fixed contract price for a notional amount of our production. As of June 30, 2021, we had net liabilities of $421 million for our derivative commodity positions which are carried at fair value, using industry-standard models with various inputs, including the forward curve for the relevant price index. For more information on our derivative positions as of June 30, 2021, refer to Part I, Item 1 – Financial Statements, Note 8 Derivatives.

Interest-Rate Risk

In March 2018, we entered into derivative contracts that limit our interest-rate exposure with respect to a notional amount of $1.3 billion of 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. The contracts expired on May 4, 2021. We did not report any gains or losses on these contracts for the three months ended June 30, 2021 or the three months ended June 30, 2020. No settlement payments were received in either 2021 or 2020.

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 continuously monitor their financial health. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.

As of June 30, 2021, the 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 June 30, 2021 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

Item 4 Controls and Procedures

Our Chief Executive Officer and our Chief Financial Officer supervised and participated in management's 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 Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2021.

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 June 30, 2021 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION

Item 1Legal Proceedings

For additional information regarding legal proceedings, see Item 1 – Financial Statements, Note 7 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 2020 Annual Report.

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 2020 Annual Report. There were no material changes to those risk factors during the three months ended March 31, 2021.

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds

In May 2021, our Board of Directors authorized a Share Repurchase Program to acquire up to $150 million of our common stock through March 31, 2022. In August 2021, our Board of Directors increased the Share Repurchase Program by $100 million to $250 million. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time. Shares repurchased are held as treasury stock.

Our share repurchase activity for the three months ended June 30, 2021 was as follows:


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(a)
April 1, 2021 - April 30, 2021	—	$	—	—	$	—
May 1, 2021 - May 31, 2021	161,017	$	29.48	161,017	—
June 1, 2021 - June 30, 2021	1,279,186	$	31.82	1,279,186	—
Total	1,440,203			1,440,203	$	—

(a)The dollar value of shares that may yet be purchased under the Share Repurchase Program totaled $105 million as of June 30, 2021 and is currently $205 million.

Item 5 Other Disclosures

None.

Item 6 Exhibits


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			First Amendment to the Credit Agreement, dated as of May 7, 2021, 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 May 1 0 , 2021 and incorporated herein by reference ).

10.2			Employment Agreement by and between Shawn M. Kerns and California Resources Corporation, dated June 8, 2021 (filed as Exhibit 10.1 to the Registrant's Current Report on Form 8 -K filed June 11 , 2021 and incorporated herein by reference).

10.3			Employment Agreement by and between Francisco J. Leon and California Resources Corporation, dated June 8, 2021 (filed as Exhibit 10.2 to the Registrant's Current Report on Form 8 -K filed June 11 , 2021 and incorporated herein by reference).

10.4*			Employment Agreement by and between Michael L. Preston and California Resources Corporation, dated June 8, 2021.

10.5*			Employment Agreement by and between Jay A. Bys and California Resources Corporation, dated June 8, 2021.

10.6*			Employment Agreement by and between Chris Gould and California Resources Corporation, dated June 1 4 , 2021.

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

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

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

101.INS*			Inline XBRL Instance Document.

101.SCH*			Inline XBRL Taxonomy Extension Schema Document.

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

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

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

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

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

* - Filed herewith

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:	August 5, 2021	/s/ Noelle M. Repetti
		Noelle M. Repetti
		Vice President and Controller
		(Principal Accounting Officer)