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~~September 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,~~October 31, 2021 was ~~81,879,457.~~80,392,897.

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	2124
	General	2124
	Business Environment and Industry Outlook	2124
	Production	2225
	Prices and Realizations	2427
	Statements of Operations Analysis	2629
	Liquidity and Capital Resources	3136
	2021 Capital Program	3438
	Regulatory Update	3439
	Dividends	39
	Share Repurchase Program	3439
	Divestitures	3440
	Acquisitions and Joint Ventures	3540
	Seasonality	3540
	Fixed and Variable Costs	3540
	Lawsuits, Claims, Commitments and Contingencies	3640
	Significant Accounting and Disclosure Changes	3641
	Forward-Looking Statements	3742
Item 3	Quantitative and Qualitative Disclosures About Market Risk	3944
Item 4	Controls and Procedures	3944

Part II
Item 1	Legal Proceedings	4045
Item 1A	Risk Factors	4045
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	4045
Item 5	Other Disclosures	4045
Item 6	Exhibits	4146

PART I FINANCIAL INFORMATION

Item 1Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of ~~June~~September 30, 2021 and December 31, 2020

(in millions, except share data)


		Successor					Successor
		June 30,		December 31,			September 30,		December 31,
		2021		2020			2021		2020
CURRENT ASSETS	CURRENT ASSETS					CURRENT ASSETS
Cash	Cash	$	151	$	28	Cash	$	189	$	28
Trade receivables	Trade receivables	238		177		Trade receivables	261		177
Inventories	Inventories	58		61		Inventories	60		61
Assets held for sale	Assets held for sale	50		0		Assets held for sale	53		—
Other current assets	Other current assets	80		63		Other current assets	94		63
Total current assets	Total current assets	577		329		Total current assets	657		329
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT	2,711		2,689		PROPERTY, PLANT AND EQUIPMENT	2,779		2,689
Accumulated depreciation, depletion and amortization	Accumulated depreciation, depletion and amortization	(138)		(34)		Accumulated depreciation, depletion and amortization	(192)		(34)
Total property, plant and equipment, net	Total property, plant and equipment, net	2,573		2,655		Total property, plant and equipment, net	2,587		2,655
OTHER ASSETS		90		90
OTHER NONCURRENT ASSETS						OTHER NONCURRENT ASSETS	98		90
TOTAL ASSETS	TOTAL ASSETS	$	3,240	$	3,074	TOTAL ASSETS	$	3,342	$	3,074


CURRENT LIABILITIES	CURRENT LIABILITIES					CURRENT LIABILITIES

Accounts payable	Accounts payable	248		212		Accounts payable	259		212
Liabilities associated with assets held for sale	Liabilities associated with assets held for sale	101		0		Liabilities associated with assets held for sale	124		—
Fair value of derivative contracts						Fair value of derivative contracts	275		50
Accrued liabilities	Accrued liabilities	537		261		Accrued liabilities	299		211
Total current liabilities	Total current liabilities	886		473		Total current liabilities	957		473
LONG-TERM DEBT, NET		589		597
NONCURRENT LIABILITIES						NONCURRENT LIABILITIES
Long-term debt, net						Long-term debt, net	589		597

OTHER LONG-TERM LIABILITIES		850		822
Fair value of derivative contracts						Fair value of derivative contracts	153		6
Asset retirement obligations						Asset retirement obligations	428		547
Other long-term liabilities						Other long-term liabilities	163		269

STOCKHOLDERS' EQUITY	STOCKHOLDERS' EQUITY					STOCKHOLDERS' EQUITY
Preferred stock (20,000,000 shares authorized at $0.01 par value) 0 shares outstanding at June 30, 2021 and December 31, 2020		0		0
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 0 shares held at December 31, 2020)		(45)		0
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at September 30, 2021 and December 31, 2020						Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at September 30, 2021 and December 31, 2020	—		—
Common stock (200,000,000 shares authorized at $0.01 par value) (83,367,076 and 83,319,660 shares issued; 80,775,277 and 83,319,660 shares outstanding at September 30, 2021 and December 31, 2020)						Common stock (200,000,000 shares authorized at $0.01 par value) (83,367,076 and 83,319,660 shares issued; 80,775,277 and 83,319,660 shares outstanding at September 30, 2021 and December 31, 2020)	1		1
Treasury stock (2,591,799 shares held at cost at September 30, 2021 and no shares held at December 31, 2020)						Treasury stock (2,591,799 shares held at cost at September 30, 2021 and no shares held at December 31, 2020)	(84)		—
Additional paid-in capital	Additional paid-in capital	1,273		1,268		Additional paid-in capital	1,286		1,268
Accumulated deficit	Accumulated deficit	(328)		(123)		Accumulated deficit	(225)		(123)
Accumulated other comprehensive loss		(8)		(8)
Accumulated other comprehensive gain (loss)						Accumulated other comprehensive gain (loss)	74		(8)
Total equity attributable to common stock	Total equity attributable to common stock	893		1,138		Total equity attributable to common stock	1,052		1,138
Equity attributable to noncontrolling interests	Equity attributable to noncontrolling interests	22		44		Equity attributable to noncontrolling interests	—		44
Total stockholders' equity	Total stockholders' equity	915		1,182		Total stockholders' equity	1,052		1,182
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,240	$	3,074	TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,342	$	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~~nine months ended ~~June~~September 30, 2021 and 2020

(dollars in millions, except per share data)


		Successor		Predecessor		Successor		Predecessor			Successor		Predecessor		Successor		Predecessor
		Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,			Three months ended September 30,		Three months ended September 30,		Nine months ended September 30,		Nine months ended September 30,
		2021		2020		2021		2020			2021		2020		2021		2020
REVENUES	REVENUES									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
Oil, natural gas and NGL sales										Oil, natural gas and NGL sales	$	549	$	312	$	1,459	$	987
Net (loss) gain from commodity derivatives										Net (loss) gain from commodity derivatives	(125)		—		(603)		75
Sales of purchased natural gas										Sales of purchased natural gas	95		50		241		109
Electricity sales	Electricity sales	33		19		66		32		Electricity sales	65		43		131		75
Other revenue	Other revenue	10		2		23		8		Other revenue	4		4		27		12
Total revenues		304		276		667		849
Total operating revenues										Total operating revenues	588		409		1,255		1,258

COSTS
OPERATING EXPENSES										OPERATING EXPENSES
Operating costs	Operating costs	169		127		333		319		Operating costs	190		141		523		460
General and administrative expenses	General and administrative expenses	48		69		96		129		General and administrative expenses	51		64		147		193
Depreciation, depletion and amortization	Depreciation, depletion and amortization	54		88		106		207		Depreciation, depletion and amortization	54		89		160		296
Asset impairments	Asset impairments	0		0		3		1,736		Asset impairments	25		—		28		1,736
Taxes other than on income	Taxes other than on income	37		38		77		79		Taxes other than on income	36		42		113		121
Exploration expense	Exploration expense	2		2		4		7		Exploration expense	2		2		6		9
Trading costs		30		8		91		32
Electricity cost of sales		17		14		41		30
Purchased natural gas expense										Purchased natural gas expense	53		35		144		67
Electricity generation expenses										Electricity generation expenses	29		17		70		47
Transportation costs	Transportation costs	14		8		26		21		Transportation costs	11		10		37		31
Other expenses, net		23		37		53		53
Total costs		394		391		830		2,613
Accretion expense										Accretion expense	13		10		39		30
Other operating expenses, net										Other operating expenses, net	4		12		31		45
Total operating expenses										Total operating expenses	468		422		1,298		3,035
Gain on asset divestitures										Gain on asset divestitures	(2)		—		(4)		—

OPERATING LOSS		(90)		(115)		(163)		(1,764)
OPERATING INCOME (LOSS)										OPERATING INCOME (LOSS)	122		(13)		(39)		(1,777)

NON-OPERATING (LOSS) INCOME
Reorganization items		(2)		0		(4)		0
NON-OPERATING (EXPENSES) INCOME										NON-OPERATING (EXPENSES) INCOME
Reorganization items, net										Reorganization items, net	(1)		66		(5)		66
Interest and debt expense, net	Interest and debt expense, net	(13)		(85)		(26)		(172)		Interest and debt expense, net	(14)		(28)		(40)		(200)
Net (loss) gain on early extinguishment of debt	Net (loss) gain on early extinguishment of debt	0		0		(2)		5		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		0		0		0		0
NET LOSS		(107)		(247)		(196)		(1,992)
Other non-operating expenses, net										Other non-operating expenses, net	—		(32)		(3)		(93)
INCOME (LOSS) BEFORE INCOME TAXES										INCOME (LOSS) BEFORE INCOME TAXES	107		(7)		(89)		(1,999)
Income taxes										Income taxes	—		—		—		—
NET INCOME (LOSS)										NET INCOME (LOSS)	107		(7)		(89)		(1,999)

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS									NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
Mezzanine equity	Mezzanine equity	0		(30)		0		(60)		Mezzanine equity	—		(25)		—		(85)
Stockholders' equity	Stockholders' equity	(4)		6		(9)		(15)		Stockholders' equity	(4)		3		(13)		(12)
Net income attributable to noncontrolling interests	Net income attributable to noncontrolling interests	(4)		(24)		(9)		(75)		Net income attributable to noncontrolling interests	(4)		(22)		(13)		(97)
NET LOSS ATTRIBUTABLE TO COMMON STOCK		$	(111)	$	(271)	$	(205)	$	(2,067)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK										NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	103	$	(29)	$	(102)	$	(2,096)

Net loss attributable to common stock per share
Net income (loss) attributable to common stock per share										Net income (loss) attributable to common stock per share
Basic	Basic	$	(1.34)	$	(5.47)	$	(2.46)	$	(41.84)	Basic	$	1.26	$	2.20	$	(1.23)	$	(39.64)
Diluted	Diluted	$	(1.34)	$	(5.47)	$	(2.46)	$	(41.84)	Diluted	$	1.25	$	2.20	$	(1.23)	$	(39.64)

Weighted average common shares outstanding										Weighted average common shares outstanding
Basic										Basic	81.6		49.5		82.6		49.4
Diluted										Diluted	82.4		49.5		82.6		49.4

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~~nine months ended ~~June~~September 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)


	Successor		Predecessor		Successor		Predecessor
	Three months ended September 30,		Three months ended September 30,		Nine months ended September 30,		Nine months ended September 30,
	2021		2020		2021		2020
Net income (loss)	$	107	$	(7)	$	(89)	$	(1,999)
Net income attributable to noncontrolling interests	(4)		(22)		(13)		(97)
Other comprehensive income:
Actuarial gain associated with pension and postretirement plans(a)	17		—		17		—
Net prior service cost credit(a)	65		—		65		—
Comprehensive income (loss) attributable to common stock	$	185	$	(29)	$	(20)	$	(2,096)

(a) No associated tax has been recorded for the components of other comprehensive income (loss) for the three and nine months ended September 30, 2021 and 2020.

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~~nine months ended ~~June~~September 30, 2021

(dollars in millions)


		Three months ended June 30, 2021 (Successor)																	Three months ended September 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			Common Stock		Treasury Stock		Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive (Loss) Income		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity
Balance, March 31, 2021		$	1	$	0	$	1,270	$	(217)	$	(8)	$	1,046	$	35	$	1,081
Net (loss) income(a)		—		—		—		(111)		—		(111)		4		(107)
Balance, June 30, 2021																		Balance, June 30, 2021	$	1	$	(45)	$	1,273	$	(328)	$	(8)	$	893	$	22	$	915
Net income																		Net income	—		—		—		103		—		103		4		107

Distributions to noncontrolling interest holders	Distributions to noncontrolling interest holders	—		—		—		—		—		—		(17)		(17)		Distributions to noncontrolling interest holders	—		—		—		—		—		—		(19)		(19)
Redemption of noncontrolling interest																		Redemption of noncontrolling interest	—		—		7		—		—		7		(7)		—
Share-based compensation	Share-based compensation	—		—		3		—		—		3		—		3		Share-based compensation	—		—		4		—		—		4		—		4

Repurchases of common stock	Repurchases of common stock	—		(45)		—		—		—		(45)		—		(45)		Repurchases of common stock	—		(39)		—		—		—		(39)		—		(39)

Balance, June 30, 2021		$	1	$	(45)	$	1,273	$	(328)	$	(8)	$	893	$	22	$	915
Issuance of common stock																		Issuance of common stock	—		—		2		—		—		2		—		2
Other comprehensive income																		Other comprehensive income	—		—		—		—		82		82		—		82
Balance, September 30, 2021																		Balance, September 30, 2021	$	1	$	(84)	$	1,286	$	(225)	$	74	$	1,052	$	—	$	1,052

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 $ 0 $ 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.


	Nine months ended September 30, 2021 (Successor)
	Common Stock		Treasury Stock		Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive (Loss) Income		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	—		—		—		(102)		—		(102)		13		(89)

Distributions to noncontrolling interest holders	—		—		—		—		—		—		(50)		(50)
Redemption of noncontrolling interest	—		—		7		—		—		7		(7)		—
Share-based compensation	—		—		10		—		—		10		—		10



Repurchases of common stock	—		(84)		—		—		—		(84)		—		(84)
Issuance of common stock	—		—		2		—		—		2		—		2
Other	—		—		(1)		—		—		(1)		—		(1)
Other comprehensive income	—		—		—		—		82		82		—		82
Balance, September 30, 2021	$	1	$	(84)	$	1,286	$	(225)	$	74	$	1,052	$	—	$	1,052

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~~nine months ended ~~June~~September 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		$	0	$	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		—

																			Three months ended September 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, June 30, 2020	Balance, June 30, 2020	$	0	$	5,008	$	(7,437)	$	(23)	$	(2,452)	$	76	$	(2,376)	$	828	Balance, June 30, 2020	$	—	$	5,008	$	(7,437)	$	(23)	(2,452)		$	76	$	(2,376)	$	828
Net (loss) income(a)																		Net (loss) income(a)	—		—		(29)		—		(29)		(3)		(32)		25

Distributions to noncontrolling interest holders																		Distributions to noncontrolling interest holders	—		—		—		—		—		(5)		(5)		(22)
Share-based compensation																		Share-based compensation	—		2		—		—		2		—		2		—
Modification of noncontrolling interest																		Modification of noncontrolling interest	—		138		—		—		138		—		138		(138)
Shares cancelled for taxes and other																		Shares cancelled for taxes and other	—		—		—		—		—		—		—		(1)
Balance, September 30, 2020																		Balance, September 30, 2020	$	—	$	5,148	$	(7,466)	$	(23)	$	(2,341)	$	68	$	(2,273)	$	692


		Six months ended June 30, 2020 (Predecessor)																	Nine months ended September 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)			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	Balance, December 31, 2019	$	0	$	5,004	$	(5,370)	$	(23)	(389)		$	93	$	(296)	$	802	Balance, December 31, 2019	$	—	$	5,004	$	(5,370)	$	(23)	(389)		$	93	$	(296)	$	802
Net (loss) income(a)	Net (loss) income(a)	—		—		(2,067)		—		(2,067)		15		(2,052)		60		Net (loss) income(a)	—		—		(2,096)		—		(2,096)		12		(2,084)		85
Contributions from noncontrolling interest holders	Contributions from noncontrolling interest holders			—		—		—		—				—		2		Contributions from noncontrolling interest holders	—		—		—		—		—		—		—		1
Distributions to noncontrolling interest holders	Distributions to noncontrolling interest holders	—		—		—		—		—		(32)		(32)		(36)		Distributions to noncontrolling interest holders	—		—		—		—		—		(37)		(37)		(58)
Share-based compensation, net		—		4		—		—		4		—		4		—
Share-based compensation																		Share-based compensation	—		6		—		—		6		—		6		—
Modification of noncontrolling interest																		Modification of noncontrolling interest	—		138		—		—		138		—		138		(138)

Balance, June 30, 2020		$	0	$	5,008	$	(7,437)	$	(23)	$	(2,452)	$	76	$	(2,376)	$	828
Balance, September 30, 2020																		Balance, September 30, 2020	$	—	$	5,148	$	(7,466)	$	(23)	$	(2,341)	$	68	$	(2,273)	$	692

(a)For the three months ended ~~June~~September 30, 2020, we allocated ~~$24~~$22 million of net income to noncontrolling interest holders, of which a $6$3 million net loss was included in stockholders' equity and ~~$30~~$25 million was included in mezzanine equity on our condensed consolidated balance sheet. The remaining net loss of ~~$271~~$29 million for the three months ended ~~June~~September 30, 2020 was attributed to holders of our common stock and included in stockholders' equity on our condensed consolidated balance sheet. For the ~~six~~nine months ended ~~June~~September 30, 2020, we allocated ~~$75~~$97 million of net income to noncontrolling interest holders, of which ~~$15~~$12 million was included in stockholders' equity and ~~$60~~$85 million was included in mezzanine equity on our condensed consolidated balance sheet. The remaining net loss of ~~$2,067~~$2,096 million for the ~~six~~nine months ended ~~June~~September 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 2020 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~~nine months ended ~~June~~September 30, 2021 and 2020

(dollars in millions)


		Successor		Predecessor		Successor		Predecessor			Successor		Predecessor		Successor		Predecessor
		Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,			Three months ended September 30,		Three months ended September 30,		Nine months ended September 30,		Nine months ended September 30,
		2021		2020		2021		2020			2021		2020		2021		2020
CASH FLOW FROM OPERATING ACTIVITIES	CASH FLOW FROM OPERATING ACTIVITIES									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:
Net income (loss)										Net income (loss)	$	107	$	(7)	$	(89)	$	(1,999)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:										Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	Depreciation, depletion and amortization	54		88		106		207		Depreciation, depletion and amortization	54		89		160		296
Asset impairments	Asset impairments	0		0		3		1,736		Asset impairments	25		—		28		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) from commodity derivatives										Net loss (gain) from commodity derivatives	125		—		603		(75)
Net settlement (payments) proceeds from commodity derivatives										Net settlement (payments) proceeds from commodity derivatives	(99)		2		(220)		105
Net loss (gain) on early extinguishment of debt	Net loss (gain) on early extinguishment of debt	0		0		2		(5)		Net loss (gain) on early extinguishment of debt	—		—		2		(5)
Amortization of deferred gain	Amortization of deferred gain	0		(16)		0		(33)		Amortization of deferred gain	—		(6)		—		(39)
Gain on asset divestiture		0		0		(2)		0

Gain on asset divestitures										Gain on asset divestitures	(2)		—		(4)		—
Reorganization items, net (non-cash)										Reorganization items, net (non-cash)	—		(125)		—		(125)
Reorganization items, net (debtor-in-possession financing costs)										Reorganization items, net (debtor-in-possession financing costs)	—		25		—		25

Other non-cash charges to income, net	Other non-cash charges to income, net	22		14		29		22		Other non-cash charges to income, net	17		47		46		69
Changes in operating assets and liabilities, net	Changes in operating assets and liabilities, net	(25)		17		(25)		130		Changes in operating assets and liabilities, net	(45)		23		(70)		153
Net cash provided by (used in) operating activities		127		(135)		274		93
Net cash provided by operating activities										Net cash provided by operating activities	182		48		456		141

CASH FLOW FROM INVESTING ACTIVITIES	CASH FLOW FROM INVESTING ACTIVITIES									CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	Capital investments	(50)		(3)		(77)		(33)		Capital investments	(51)		(4)		(128)		(37)
Changes in accrued capital investments	Changes in accrued capital investments	8		(9)		13		(28)		Changes in accrued capital investments	5		3		18		(25)
Proceeds from asset divestitures	Proceeds from asset divestitures	0		0		2		41		Proceeds from asset divestitures	11		—		13		41

Acquisitions										Acquisitions	(53)		—		(53)		—
Other	Other	(1)		(3)		(1)		(7)		Other	—		—		(1)		(7)
Net cash used in investing activities	Net cash used in investing activities	(43)		(15)		(63)		(27)		Net cash used in investing activities	(88)		(1)		(151)		(28)

CASH FLOW FROM FINANCING ACTIVITIES	CASH FLOW FROM FINANCING ACTIVITIES									CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from Revolving Credit Facility	Proceeds from Revolving Credit Facility	0		0		16		0		Proceeds from Revolving Credit Facility	—		—		16		—
Repayments of Revolving Credit Facility	Repayments of Revolving Credit Facility	0		0		(115)		0		Repayments of Revolving Credit Facility	—		—		(115)		—
Proceeds from 2014 Revolving Credit Facility	Proceeds from 2014 Revolving Credit Facility	0		346		0		795		Proceeds from 2014 Revolving Credit Facility	—		2		—		797
Repayments of 2014 Revolving Credit Facility	Repayments of 2014 Revolving Credit Facility	0		(123)		0		(582)		Repayments of 2014 Revolving Credit Facility	—		(733)		—		(1,315)
Proceeds from debtor-in-possession facilities										Proceeds from debtor-in-possession facilities	—		782		—		782
Repayments of debtor-in-possession facilities										Repayments of debtor-in-possession facilities	—		(49)		—		(49)
Debtor-in-possession financing costs										Debtor-in-possession financing costs	—		(25)		—		(25)
Proceeds from Senior Notes	Proceeds from Senior Notes	0		0		600		0		Proceeds from Senior Notes	—		—		600		—
Debt repurchases	Debt repurchases	0		0		0		(3)		Debt repurchases	—		—		—		(3)
Debt issuance costs	Debt issuance costs	(1)		0		(13)		0		Debt issuance costs	—		—		(13)		—
Repayment of Second Lien Term Loan	Repayment of Second Lien Term Loan	0		0		(200)		0		Repayment of Second Lien Term Loan	—		—		(200)		—
Repayment of EHP Notes	Repayment of EHP Notes	0		0		(300)		0		Repayment of EHP Notes	—		—		(300)		—
Repayment of 2020 Senior Notes	Repayment of 2020 Senior Notes	0		0		0		(100)		Repayment of 2020 Senior Notes	—		—		—		(100)
Repurchases of common stock	Repurchases of common stock	(45)		0		(45)		0		Repurchases of common stock	(39)		—		(84)		—
Proceeds from warrants exercised										Proceeds from warrants exercised	2		—		2		—
Contribution from noncontrolling interest holders	Contribution from noncontrolling interest holders	0		0		0		2		Contribution from noncontrolling interest holders	—		—		—		1
Distributions paid to noncontrolling interest holders	Distributions paid to noncontrolling interest holders	(17)		(24)		(31)		(68)		Distributions paid to noncontrolling interest holders	(19)		(27)		(50)		(95)

Shares cancelled for taxes		0		0		0		(1)
Net cash (used in) provided by financing activities		(63)		199		(88)		43
Increase in cash		21		49		123		109
Shares cancelled for taxes and other										Shares cancelled for taxes and other	—		(1)		—		(1)
Net cash used in financing activities										Net cash used in financing activities	(56)		(51)		(144)		(8)
Increase (decrease) in cash										Increase (decrease) in cash	38		(4)		161		105
Cash—beginning of period	Cash—beginning of period	130		77		28		17		Cash—beginning of period	151		126		28		17
Cash—end of period	Cash—end of period	$	151	$	126	$	151	$	126	Cash—end of period	$	189	$	122	$	189	$	122

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~~September 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).

Certain prior period amounts have been reclassified to conform to the current period presentation.

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					Successor
		June 30,		December 31,			September 30,		December 31,
		2021		2020			2021		2020
		(in millions)					(in millions)
Amounts due from joint interest partners	Amounts due from joint interest partners	$	48	$	42	Amounts due from joint interest partners	$	37	$	42
Receivables for premiums on derivative contracts	Receivables for premiums on derivative contracts	8		0		Receivables for premiums on derivative contracts	7		—
Fair value of derivative contracts						Fair value of derivative contracts	8		—
Prepaid expenses	Prepaid expenses	19		20		Prepaid expenses	13		20
Prepaid greenhouse gas allowances						Prepaid greenhouse gas allowances	25		—
Other	Other	5		1		Other	4		1
Other current assets	Other current assets	$	80	$	63	Other current assets	$	94	$	63

Other noncurrent assets - Other noncurrent assets includes the following:


		Successor					Successor
		June 30,		December 31,			September 30,		December 31,
		2021		2020			2021		2020
		(in millions)					(in millions)
Operating lease right-of-use assets	Operating lease right-of-use assets	35		38		Operating lease right-of-use assets	$	42	$	38
Deferred financing costs - Revolving Credit Facility	Deferred financing costs - Revolving Credit Facility	14		17		Deferred financing costs - Revolving Credit Facility	12		17
Emission reduction credits	Emission reduction credits	11		11		Emission reduction credits	11		11
Prepaid power plant maintenance	Prepaid power plant maintenance	17		14		Prepaid power plant maintenance	19		14
Fair value of derivative contracts						Fair value of derivative contracts	2		—
Long-term deposits and other	Long-term deposits and other	13		10		Long-term deposits and other	12		10
Other assets		$	90	$	90
Other noncurrent assets						Other noncurrent assets	$	98	$	90

Accrued liabilities — Accrued liabilities includes the following:


		Successor					Successor
		June 30,		December 31,			September 30,		December 31,
		2021		2020			2021		2020
		(in millions)					(in millions)
Accrued employee-related costs	Accrued employee-related costs	$	61	$	72	Accrued employee-related costs	$	62	$	72
Accrued taxes other than on income	Accrued taxes other than on income	31		36		Accrued taxes other than on income	39		36
Asset retirement obligations	Asset retirement obligations	49		50		Asset retirement obligations	51		50
Accrued interest	Accrued interest	20		1		Accrued interest	8		1
Lease liability	Lease liability	8		7		Lease liability	8		7
Fair value of derivative contracts		265		50

Deferred premiums on derivative contracts	Deferred premiums on derivative contracts	28		18		Deferred premiums on derivative contracts	56		18
Net settlement payments due on derivative contracts	Net settlement payments due on derivative contracts	34		3		Net settlement payments due on derivative contracts	37		3
Other	Other	41		24		Other	38		24
Accrued liabilities	Accrued liabilities	$	537	$	261	Accrued liabilities	$	299	$	211

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


		Successor					Successor
		June 30,		December 31,			September 30,		December 31,
		2021		2020			2021		2020
		(in millions)					(in millions)
Asset retirement obligations		$	448	$	547

Deferred compensation and postretirement	Deferred compensation and postretirement	181		184		Deferred compensation and postretirement	$	97	$	184
Lease liability	Lease liability	31		35		Lease liability	38		35
Fair value of derivative contracts		156		6

Deferred premiums on derivative contracts	Deferred premiums on derivative contracts	16		31		Deferred premiums on derivative contracts	14		31
Other	Other	18		19		Other	14		19
Other long-term liabilities	Other long-term liabilities	$	850	$	822	Other long-term liabilities	$	163	$	269

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


		Successor		Predecessor		Successor		Predecessor			Successor		Predecessor		Successor		Predecessor
		Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,			Three months ended September 30,		Three months ended September 30,		Nine months ended September 30,		Nine months ended September 30,
		2021		2020		2021		2020			2021		2020		2021		2020
(in millions)	(in millions)									(in millions)
Oil	Oil	$	380	$	193	$	711	$	549	Oil	$	413	$	246	$	1,124	$	795
Natural gas	Natural gas	45		26		92		64		Natural gas	69		34		161		98
NGLs	NGLs	53		26		107		62		NGLs	67		32		174		94
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	478	$	245	$	910	$	675	Oil, natural gas and NGL sales	$	549	$	312	$	1,459	$	987

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


		Successor		Predecessor		Successor		Predecessor			Successor		Predecessor		Successor		Predecessor
		Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,			Three months ended September 30,		Three months ended September 30,		Nine months ended September 30,		Nine months ended September 30,
		2021		2020		2021		2020			2021		2020		2021		2020
(in millions)	(in millions)									(in millions)
Accretion expense		$	13	$	10	$	26	$	20
Severance and termination costs	Severance and termination costs	1		0		15		0		Severance and termination costs	$	—	$	—	$	15	$	—
Deficiency payment on a pipeline delivery contract	Deficiency payment on a pipeline delivery contract	0		20		0		20		Deficiency payment on a pipeline delivery contract	—		—		—		20
Idle well fees										Idle well fees	—		—		6		4
Power plant interruption										Power plant interruption	—		—		—		7
Ad valorem fees										Ad valorem fees	—		4		—		4
Other, net	Other, net	9		7		12		13		Other, net	4		8		10		10
Other expenses, net	Other expenses, net	$	23	$	37	53		53		Other expenses, net	$	4	$	12	$	31	$	45

Reorganization items, net represent the one-time costs related to our reorganization and consists of the following:


	Successor		Predecessor		Successor		Predecessor
	Three months ended September 30,		Three months ended September 30,		Nine months ended September 30,		Nine months ended September 30,
	2021		2020		2021		2020
(in millions)
Unamortized deferred gain and issuance costs, net(a)	$	—	$	125	$	—	$	125
Legal, professional and other, net	(1)		(34)		(5)		(34)
Debtor-in-possession financing costs	—		(25)		—		(25)
Total reorganization items, net	$	(1)	$	66	$	(5)	$	66

(a)Reflects a non-cash adjustment to the carrying amount of our pre-emergence long-term debt to state such amounts at face value upon filing our bankruptcy petition on July 15,2020.

Supplemental Cash Flow Information

We did 0tnot make U.S. federal and state income tax payments during the three and ~~six~~nine months ended ~~June~~September 30, 2021 and 2020. Interest paid, net of capitalized amounts, totaled $2$23 million and $6$21 million for the three months ended ~~June~~September 30, 2021 and 2020, respectively. Interest paid, net of capitalized amounts, totaled $4$27 million and ~~$51~~$72 million for the ~~six~~nine months ended ~~June~~September 30, 2021 and 2020, respectively. Cash paid for reorganization items during the three and ~~six~~nine months ended ~~June~~September 30, 2021 was $2$1 million and $4$5 million respectively, for legal, professional and other ~~fees.~~fees, net. Cash paid for reorganization items during the three and nine months ended September 30, 2020 was $7 million for legal, professional and other fees, net.

Non-cash investing activities included $2 million of purchase price adjustments related to the acquisition of the working interests held by Macquarie Infrastructure and Real Assets Inc. (MIRA) for the three and nine months ended September 30, 2021.

Non-cash financing activities in the three and nine months ended September 30, 2020 included a $138 million downward adjustment to mezzanine equity related to a Settlement Agreement with one of our joint venture partners. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report for more on the Settlement Agreement.

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 1213 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					Successor
		June 30,		December 31,			September 30,		December 31,
		2021		2020			2021		2020
		(in millions)					(in millions)
Materials and supplies	Materials and supplies	$	56	$	58	Materials and supplies	$	55	$	58
Finished goods	Finished goods	2		3		Finished goods	5		3
Inventories	Inventories	$	58	$	61	Inventories	$	60	$	61

NOTE 5 DEBT

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


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

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

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

EHP Notes	EHP Notes	0		300		6%	October 27, 2027	EHP Notes	—		300		6%	October 27, 2027
Senior Notes	Senior Notes	600		0		7.125%	February 1, 2026	Senior Notes	600		—		7.125%	February 1, 2026
Principal Amount		$	600	$	599
Principal amount								Principal amount	$	600	$	599
Unamortized debt issuance costs	Unamortized debt issuance costs	(11)		(2)				Unamortized debt issuance costs	(11)		(2)
Long-term debt, net	Long-term debt, net	$	589	$	597			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~~semi-annually and was ~~most recently set~~reaffirmed at $1.2 billion in ~~May~~November 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~~September 30, 2021, our availability under ~~the~~our Revolving Credit ~~facility~~Facility was as follows:


	Successor
	~~June~~September 30,
	2021
	(in millions)
Borrowing capacity	$	492
Outstanding letters of credit	~~(125)~~(133)
Availability	$	~~367~~359

Senior Notes

On January 20, 2021, we ~~completed an offering of~~issued $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~~September 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~~estimate 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					Successor
		June 30,		December 31,			September 30,		December 31,
		2021		2020			2021		2020
		(in millions)					(in millions)
Variable rate debt	Variable rate debt	$	0	$	299	Variable rate debt	$	—	$	299
Fixed rate debt	Fixed rate debt					Fixed rate debt

Senior Notes	Senior Notes	633		0		Senior Notes	634		—
EHP Notes	EHP Notes	0		300		EHP Notes	—		300
Fair Value of Long-Term Debt	Fair Value of Long-Term Debt	$	633	$	599	Fair Value of Long-Term Debt	$	634	$	599

NOTE 6 ASSETS HELD FOR SALE

InDuring 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, before purchase price adjustments, plus additional earn-out consideration that is linked to future commodity prices. The consideration, exclusive of the earn-out, includes $82 million of cash to be paid at closing (subject to purchase price adjustments) 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~~September 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~~Refer to ~~close~~ Note 16 Subsequent Events for information on the closing of this sale.

NOTE 7 ACQUISITIONS AND DIVESTITURES

Acquisitions

In April 2017, we entered into a development joint venture with MIRA to develop certain of our oil and natural gas properties in the ~~second half of 2021.~~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 purchase prices adjustments and transaction costs. We accounted for this transaction as an asset acquisition. Prior to the acquisition, our consolidated results reflect only our 10% working interest share in the productive wells.

Divestitures

During the three months ended September 30, 2021, we sold unimproved land for $11 million in proceeds recognizing a $2 million gain. During the nine months ended September 30, 2021 we sold non-core assets, including unimproved land, for $13 million in proceeds recognizing a $4 million gain.

During the nine months ended September 30, 2020, we sold royalty interests and a non-core asset for $41 million. These divestitures were accounted for as normal retirements with no gain or loss recognized.

NOTE 78 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 for these items at ~~June~~September 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 2 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~~September 2021, we ~~entered into an amendment allowing us to accept certain land use requirements which~~accepted the indemnification claim from Oxy and will ~~relieve us~~be challenging the order from ~~our remaining obligation on or before May 2022.~~BSEE.

NOTE 89 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~~nine months ended ~~June~~September 30, 2021 and 2020. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as accounting hedges.

Our Revolving Credit Facility requires ~~that we hedge~~us to maintain hedges on a ~~significant~~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 ~~a period~~the first 24 months after the closing of ~~36 months from the effective date of the facility. In addition,~~ the Revolving Credit Facility ~~requires~~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 ~~we maintain hedges on production~~must be used for ~~not less than two years from each quarter end.~~a portion of those hedges.

1314

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. The percentage of our crude oil production hedged is calculated exclusive of offsetting positions on our derivative contracts.

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


		Q3 2021		Q4 2021		Q1 2022		Q2 2022		2H 2022		2023			Q4 2021		Q1 2022		Q2 2022		Q3 2022		Q4 2022		2023
Sold Calls	Sold Calls													Sold Calls
Barrels per day	Barrels per day	36,688		37,037		35,347		35,343		28,773		14,790		Barrels per day	37,037		35,347		35,343		34,380		25,167		14,790
Weighted-average price per barrel	Weighted-average price per barrel	$	50.47	$	60.75	$	60.37	$	60.63	$	59.07	$	58.01	Weighted-average price per barrel	$	60.75	$	60.37	$	60.63	$	60.76	$	57.82	$	58.01

Purchased Puts	Purchased Puts													Purchased Puts
Barrels per day	Barrels per day	36,943		35,820		35,347		35,343		28,773		14,790		Barrels per day	35,820		56,814		57,850		57,855		43,121		14,790
Weighted-average price per barrel	Weighted-average price per barrel	$	40.18	$	40.19	$	40.57	$	41.13	$	40.70	$	40.00	Weighted-average price per barrel	$	40.19	$	48.29	$	48.98	$	49.48	$	50.05	$	40.00

Sold Puts	Sold Puts													Sold Puts
Barrels per day	Barrels per day	14,647		14,193		6,869		0		2,674		0		Barrels per day	14,193		28,336		22,507		27,475		19,302		—
Weighted-average price per barrel	Weighted-average price per barrel	$	30.00	$	32.00	$	32.00	$	0	$	32.00	$	0	Weighted-average price per barrel	$	32.00	$	38.06	$	40.00	$	38.84	$	39.44	$	—

Swaps	Swaps													Swaps
Barrels per day	Barrels per day	11,063		11,922		10,869		8,669		8,386		6,930		Barrels per day	13,922		12,369		10,669		10,476		17,263		10,101
Weighted-average price per barrel	Weighted-average price per barrel	$	51.02	$	52.61	$	52.62	$	51.31	$	51.22	$	52.15	Weighted-average price per barrel	$	54.86	$	54.38	$	54.12	$	53.97	$	58.79	$	55.69

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.

1415

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~~September 30, 2021 and December 31, 2020:


June 30, 2021 (Successor)
September 30, 2021 (Successor)								September 30, 2021 (Successor)
Classification	Classification	Gross Amounts at Fair Value		Netting		Net Fair Value		Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	Assets	(in millions)						Assets	(in millions)
Other current assets	Other current assets	$	6	$	(6)	$	0	Other current assets	$	29	$	(21)	$	8
Other assets		18		(18)		0
Other noncurrent assets								Other noncurrent assets	27		(25)		2

Liabilities	Liabilities							Liabilities
Accrued liabilities		(271)		6		(265)
Other long-term liabilities		(174)		18		(156)
Current - Fair value of derivative contracts								Current - Fair value of derivative contracts	(296)		21		(275)
Noncurrent - Fair value of derivative contracts								Noncurrent - Fair value of derivative contracts	(178)		25		(153)
		$	(421)	$	0	$	(421)		$	(418)	$	—	$	(418)


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

Liabilities	Liabilities							Liabilities
Accrued liabilities		(71)		21		(50)
Other long-term liabilities		(69)		63		(6)
Current - Fair value of derivative contracts								Current - Fair value of derivative contracts	(71)		21		(50)
Noncurrent - Fair value of derivative contracts								Noncurrent - Fair value of derivative contracts	(69)		63		(6)
		$	(56)	$	0	$	(56)		$	(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~~derivatives on our condensed consolidated statements of operations for the three and ~~six~~nine months ended ~~June~~September 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 910 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) ~~was~~were calculated using the treasury stock method for the three and ~~six~~nine months ended ~~June~~September 30, 2021 and the two-class method for the three and ~~six~~nine months ended ~~June~~September 30, 2020, which is required for participating securities. Certain of our restricted and performance stock unit awards outstanding during the ~~six~~nine months ended ~~June~~September 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,~~subsequent to our emergence from bankruptcy, as described in Note 1314 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.

1516

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


		Successor		Predecessor		Successor		Predecessor			Successor		Predecessor		Successor		Predecessor
		Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,			Three months ended September 30,		Three months ended September 30,		Nine months ended September 30,		Nine months ended September 30,
		2021		2020		2021		2020			2021		2020		2021		2020
(in millions, except per-share amounts)	(in millions, except per-share amounts)									(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS	Numerator for Basic and Diluted EPS									Numerator for Basic and Diluted EPS
Net loss		$	(107)	$	(247)	$	(196)	$	(1,992)
Net income (loss)										Net income (loss)	$	107	$	(7)	$	(89)	$	(1,999)
Less: net income attributable to noncontrolling interests	Less: net income attributable to noncontrolling interests	(4)		(24)		(9)		(75)		Less: net income attributable to noncontrolling interests	(4)		(22)		(13)		(97)
Net loss attributable to common stock		$	(111)	$	(271)	$	(205)	$	(2,067)
Net income (loss) attributable to common stock										Net income (loss) attributable to common stock	103		(29)		(102)		(2,096)
Modification of noncontrolling interest(a)										Modification of noncontrolling interest(a)	—		138		—		138
Net income (loss) available to common stockholders										Net income (loss) available to common stockholders	$	103	$	109	$	(102)	$	(1,958)

Denominator for Basic and Diluted EPS
Denominator for Basic EPS										Denominator for Basic EPS
Weighted-average shares	Weighted-average shares	83.1		49.5		83.2		49.4		Weighted-average shares	81.6		49.5		82.6		49.4

Potential Dilutive Common Shares:										Potential Dilutive Common Shares:

Restricted Stock Units										Restricted Stock Units	0.4		—		—		—
Performance Stock Units										Performance Stock Units	0.4		—		—		—

Denominator for Diluted Earnings per Share										Denominator for Diluted Earnings per Share
Weighted Average Shares - Diluted										Weighted Average Shares - Diluted	82.4		49.5		82.6		49.4

EPS	EPS									EPS
Basic	Basic	$	(1.34)	$	(5.47)	$	(2.46)	$	(41.84)	Basic	$	1.26	$	2.20	$	(1.23)	$	(39.64)
Diluted	Diluted	$	(1.34)	$	(5.47)	$	(2.46)	$	(41.84)	Diluted	$	1.25	$	2.20	$	(1.23)	$	(39.64)

Weighted-average anti-dilutive shares		6.4		5.2		5.9		4.9

(a)Modification of noncontrolling interest relates to the deemed redemption of ECR's noncontrolling interest in the Ares JV in the third quarter of 2020. For more information on the Ares JV and the Settlement Agreement, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report.

Diluted earnings per share for the three and nine months ended September 30, 2021 excludes 4.3 million common shares issuable upon exercise of warrants that were out-of-the-money based on the average stock price for those periods. See Note 15 Equity for information on the terms of the warrants.

Diluted earnings per share for the nine months ended September 30, 2021 excludes 0.9 million weighted-average common shares underlying our Restricted Stock Units and 0.6 million weighted-average common shares underlying our Performance Stock Units. Our Performance Stock Units have a market condition, and an additional 0.2 million potential common shares did not meet the market-based criteria as of September 30, 2021.

Diluted earnings per share for the three and nine months ended September 30, 2020 excludes 1.25 million potential common shares issuable upon exercise of warrants that were out-of-the-money based on the average stock price for those periods. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report for more information on the terms of these warrants. Diluted earnings per share for the three months ended September 30, 2020 excludes 0.2 million, 0.5 million and 1.4 million weighted-average common shares underlying our then Restricted Stock Units, Performance Stock Units and stock options, respectively. Diluted earnings per share for the nine months ended September 30, 2020 calculation excludes 0.6 million, 0.8 million and 1.7 million weighted-average common shares underlying our then Restricted Stock Units, Performance Stock Units, and stock options, respectively.

NOTE 1011 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~~nine months ended ~~June~~September 30, 2021 and 2020:


		Successor				Predecessor					Successor				Predecessor
		Three months ended June 30,				Three months ended June 30,					Three months ended September 30,				Three months ended September 30,
		2021				2020					2021				2020
		Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit			Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
(in millions)	(in millions)									(in millions)
Service cost	Service cost	$	1	$	1	$	1	$	1	Service cost	$	—	$	1	$	—	$	1
Interest cost	Interest cost	0		1		0		1		Interest cost	1		—		—		1
Expected return on plan assets		(1)		0		0		0

Curtailment gain										Curtailment gain	—		(1)		—		—
Total	Total	$	0	$	2	$	1	$	2	Total	$	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 0 2 1 2
Expected return on plan assets (1) 0 0 0
Total $ 0 $ 4 $ 2 $ 4


	Successor				Predecessor
	Nine months ended September 30,				Nine months ended September 30,
	2021				2020
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
(in millions)
Service cost	$	1	$	3	$	1	$	3
Interest cost	1		2		1		3
Expected return on plan assets	(1)		—		(1)		—
Recognized actuarial loss	—		—		1		—

Curtailment gain	—		(1)		$	—	$	—
Total	$	1	$	4	$	2	$	6

We contributed $1 million and $2 million to our defined benefit plans during the three and ~~six~~nine months ended ~~June~~September 30, ~~2021.~~2021, respectively. We do not expect to ~~satisfy our minimum funding requirements with~~make any significant contributions ~~of approximately $3 million~~ to our defined benefit pension plans during the remainder of 2021.

We did 0tnot make significant contributions to our defined benefit pension plans for the three and ~~six~~nine months ended ~~June~~September 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,~~these periods, we deferred contributions to our defined benefit pension plans of approximately $5 million under the Coronavirus Aid, Relief, and Economic Security Act, which wewas enacted on March 27, 2020. Our 2020 plan contributions were funded in December 2020.

In the third quarter of 2021, we adopted a postretirement benefit design change, which terminated the employer cost sharing for post age 65 retiree health benefits effective as of January 1, 2022. Our retiree health care benefits provided up to age 65 to current and future retirees who meet certain eligibility requirements were not affected by this change. As a result of this change, our postretirement medical benefit obligation was remeasured as of September 30, 2021. The remeasurement resulted in a decrease to the benefit obligation of $82 million with a corresponding increase to accumulated other comprehensive income. The benefit from the change in plan design will be recognized in our statement of operations over the average remaining years of future service for active employees as a component of other non-operating expenses, net.

NOTE 1112 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~~nine months ended ~~June~~September 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 0zero 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 if oil prices continue at current levels, there is a reasonable possibility that some or all of this valuation 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 1213 ASSET IMPAIRMENTS

The following table presents a summary of our asset impairments:


		Successor		Predecessor			Successor		Predecessor		Successor		Predecessor
		Six months ended June 30,		Six months ended June 30,			Three months ended September 30,		Three months ended September 30,		Nine months ended September 30,		Nine months ended September 30,
		2021		2020			2021		2020		2021		2020
(in millions)	(in millions)					(in millions)
Proved oil and natural gas properties	Proved oil and natural gas properties	$	0	$	1,487	Proved oil and natural gas properties	$	—	$	—	$	—	$	1,487
Unproved properties	Unproved properties	0		228		Unproved properties	—		—		—		228
Other	Other	3		21		Other	25		—		28		21
Total	Total	$	3	$	1,736	Total	$	25	$	—	$	28	$	1,736

We ~~recognized a $3 million~~recorded an impairment charge of $25 million during the ~~six~~three months ended ~~June~~September 30, 2021 related to the write-down of a commercial office building located in Bakersfield, California to fair value, which was ~~triggered by the change in our business strategy and capital allocation priorities resulting~~determined based on a market approach (using Level 3 inputs in the ~~abandonment~~fair value hierarchy). The decline in value of ~~certain capital projects.~~the commercial office building primarily relates to limited demand for office space of this size and type in the Bakersfield market and general trends in commercial real estate due to the COVID-19 pandemic. We do not own any other commercial office buildings. No impairment charges were recorded during the same period in 2020.

~~During~~We recorded impairment charges of $28 million for the ~~six~~nine months ended ~~June~~September 30, 2021 which included the $25 million write-down of commercial office space in Bakersfield, California to fair value and a $3 million write-off of capitalized costs related to projects which were abandoned. For the same period in 2020, we recorded ~~a $1.7 billion~~an impairment ~~which was triggered by~~charge of $1,736 million due to the sharp drop in commodity prices in March 2020, which included $1,487 million 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 ~~the end of the first quarter of 2020.~~that time. 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~~nine months ended ~~June~~September 30, 2020.

NOTE 1314 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			Successor		Predecessor		Successor		Predecessor
		Three months ended June 30,		Three months ended June 30,		Six months ended June 30,		Six months ended June 30,			Three months ended September 30,		Three months ended September 30,		Nine months ended September 30,		Nine months ended September 30,
		2021		2020		2021		2020			2021		2020		2021		2020
(in millions)	(in millions)									(in millions)
General and administrative expenses	General and administrative expenses	$	4	$	1	$	6	$	2	General and administrative expenses	$	5	$	1	$	11	$	3

Operating costs										Operating costs	1		—		1		—
Total stock-based compensation expense										Total stock-based compensation expense	$	6	$	1	$	12	$	3

For the three and ~~six~~nine months ended ~~June~~September 30, 2021 and 2020, we did 0tnot recognize any income tax benefit related to our stock-based compensation. For the three ~~and six~~ months ended ~~June~~September 30, 2020, we made insignificant cash payments for the cash-settled portion of our pre-emergence awards. For the nine months ended September 30, 2020, we made cash payments of ~~$7 million and~~ $15 million for the cash-settled portion of our pre-emergence ~~awards, respectively.~~awards.

Management Incentive Plan

Restricted Stock Units

Executives and non-employee directors were granted RSUs during the first ~~half~~nine months 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~~nine months ended ~~June~~September 30, 2021:


		Number of Units	Weighted-Average Grant-Date Fair Value			Number of Units	Weighted-Average Grant-Date Fair Value
		(in thousands)				(in thousands)
Unvested at December 31, 2020 (Successor)	Unvested at December 31, 2020 (Successor)	0	$	0	Unvested at December 31, 2020 (Successor)	—	$	—
Granted	Granted	1,180	$	24.74	Granted	1,185	$	24.75
Cancelled or Forfeited	Cancelled or Forfeited	(36)	$	24.50	Cancelled or Forfeited	(67)	$	24.50
Unvested at June 30, 2021 (Successor)		1,144	0
Unvested at September 30, 2021 (Successor)					Unvested at September 30, 2021 (Successor)	1,118	0

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~~September 30, 2021, the unrecognized compensation expense for ~~all of~~ our unvested RSUs was approximately ~~$25~~$22 million and is expected to be recognized over a weighted-average remaining service period of approximately ~~three~~two years.

Performance Stock Units

Executives were granted PSUs during the first ~~half~~nine months of ~~2021 which contained a market condition.~~2021. 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~~nine months ended ~~June~~September 30, 2021:


		Number of Units	Weighted-Average Grant-Date Fair Value			Number of Units	Weighted-Average Grant-Date Fair Value
		(in thousands)				(in thousands)
Unvested at December 31, 2020 (Successor)	Unvested at December 31, 2020 (Successor)	0	$	0	Unvested at December 31, 2020 (Successor)	—	$	—
Granted	Granted	969	$	19.72	Granted	969	$	19.72
Cancelled or Forfeited	Cancelled or Forfeited	(21)	$	19.31	Cancelled or Forfeited	(53)	$	19.31
Unvested at June 30, 2021 (Successor)		948	0
Unvested at September 30, 2021 (Successor)					Unvested at September 30, 2021 (Successor)	916	0

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~~nine months 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 0 % 0 %
Forecast period (in years) 2 - 3 3


	Successor
	Nine months ended September 30, 2021



Expected volatility(a)	60.00% - 65.00%
Risk-free interest rate(b)	0.16% - 0.32%
Dividend yield	—	%
Forecast period (in years)	2 - 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 atwo- or 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 September 30, 2021, the unrecognized compensation expense for our unvested PSUs was approximately $14 million and is expected to be recognized over a weighted-average remaining service period of approximately two years.

Long-Term Cash Incentive Awards

On June 30, 2021, we granted $16 million of performance cash awards to approximately 500 non-executive employees where half of the award is variable with payouts ranging from 75% to 150% of the grant value. The variable portion of the award is determined based upon the attainment of specified 60-trading day volume weighted average prices for shares of our common stock preceding each vesting date. These awards vest over a three-year service period commencing on the grant date and are settled in cash. The fair value of the awards is adjusted on a quarterly basis for the cumulative change in the value determined using a Monte Carlo simulation model which runs a probabilistic assessment of our stock price during each of the three-year service periods.

The assumptions used in the Monte Carlo simulation model for the performance cash awards as of September 30, 2021 were as follows:


	Successor
	Nine months ended September 30, 2021



Expected volatility(a)	60	%
Risk-free interest rate(b)	0.47	%
Dividend yield	—	%
Forecast period (in years)	2.7

(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 the 2.7 year remaining term.

As of September 30, 2021, the unrecognized compensation expense for all of our unvested ~~PSUs~~cash-settled awards was ~~approximately $17~~$14 million and is expected to be recognized over a weighted-average remaining service period of approximately three years. The awards forfeited during the three months ended September 30, 2021 were insignificant.

NOTE 1415 EQUITY

Share Repurchase Program

In ~~May~~ 2021, our Board of Directors authorized a Share Repurchase Program to acquire up to ~~$150~~$250 million of our common stock through March 31, ~~2022. See~~2022, which was extended through June 30, 2022 as described in Note 1516 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~~September 30, 2021, we repurchased ~~1.4~~2.6 million shares of our common stock, at an average price of ~~$31.56~~$32.39 per share, through either open market purchases or aour Rule 10b5-1 plan ~~at an aggregate cost of $45~~for $84 million. Shares repurchased were held as treasury stock as of ~~June~~September 30, 2021.

Warrants

In accordance with the Plan, we reserved an aggregate 4.4 million shares of our common stock for warrants issued to holders of our Predecessor debt claims. The warrants are exercisable at an initial exercise price of $36 per share for a period of four years beginning October 27, 2020, the effective date of the Plan. The Warrant Agreement contains customary anti-dilution adjustments in the event of any stock split, reverse stock split, stock dividend, equity awards under a management incentive plan that our Board of Directors may establish pursuant to the Plan (if any) or other distributions. The warrant holder may elect, in its sole discretion, to pay cash or to exercise on a cashless basis, pursuant to which the holder will not be required to pay cash for shares of common stock upon exercise of the warrant but will instead receive fewer shares. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 15 Equity in our 2020 Annual Report for a description of our warrants.

During the three and nine months ended September 30, 2021, we issued 47,416 shares of common stock and received approximately $2 million related to warrants exercised.

BSP JV

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 was entitled to preferred distributions and, upon receiving cash distributions equal to a predetermined threshold in September 2021, the preferred interest was automatically redeemed in full under the terms of the joint venture agreement. For the three and nine months ended September 30, 2021, we distributed $19 million and $50 million, respectively, to BSP. Upon redemption, we reduced the remaining balance in noncontrolling interest to zero and increased our additional paid-in capital by the same amount. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 6 Joint Ventures in our 2020 Annual Report for more information on our BSP JV.

NOTE 1516 SUBSEQUENT EVENTS

~~Acquisitions~~Ventura Basin Divestiture

~~In April 2017, we entered into a development joint venture with Macquarie Infrastructure and Real Assets Inc. (MIRA) to develop certain~~After the quarter-end, closings for the sale of our ~~oil~~Ventura basin operations occurred with respect to the majority of the basin's assets and ~~natural gas properties~~subsequent closings are expected to occur in the ~~San Joaquin basin in exchange~~following quarters. With the divestitures closed to date, we realized $62 million of cash paid at closing (before purchase price adjustments) and our liability for ~~a 90% working interest in~~related asset retirement obligations was approximately $100 million which were assumed by the ~~related properties. In August 2021, we purchased MIRA’s entire working interest share in the conveyed assets~~buyer. See Note 6 Assets Held for ~~$53 million, before transaction costs. Prior to the acquisition, our consolidated results reflect only our 10% working interest share in the productive wells.~~Sale for more information regarding this transaction.

19Dividends

On November 11, 2021, our Board of Directors declared a quarterly cash dividend of $0.17 per share of common stock. The dividend is payable to shareholders of record at the close of business on December 1, 2021 and is expected to be paid on December 16, 2021. This quarterly dividend is made pursuant to a cash dividend policy approved by the Board of Directors, which anticipates a total annual dividend of $0.68, payable in quarterly increments of $0.17 per share of common stock. The actual declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position.

The dividend will be recorded as a reduction of additional paid-in capital.

Share Repurchase Program

~~In August~~On November 11, 2021, our Board of Directors ~~authorized an increase to~~extended the time period for our Share Repurchase Program ~~of $100 million to $250 million of our common stock~~ through ~~March 31,~~June 30, 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 are committed to energy transition in the energy sector and have some of the lowest carbon intensity production in the United States. Through our subsidiary, Carbon TerraVault, we are in the early stages of developing several carbon capture and sequestration projects in the San Joaquin Valley. Separately, we are evaluating the feasibility of a carbon capture system to be located at our Elk Hills power plant. We are also pursuing multiple front-of-the-meter and behind-the-meter solar projects.

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~~nine months ended ~~June~~September 30, 2021 compared to the same periods in 2020. Benchmark prices for Brent crude oil in the first ~~half~~nine months of 2021 increased ~~55%~~59% from the same period in 2020 as a result of steady draws on global inventories 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~~nine months ended ~~June~~September 30, 2021 and 2020:


		Three months ended June 30,				Six months ended June 30,					Three months ended September 30,				Nine months ended September 30,
		2021		2020		2021		2020			2021		2020		2021		2020
Brent oil ($/Bbl)	Brent oil ($/Bbl)	$	69.02	$	33.27	$	65.06	$	42.12	Brent oil ($/Bbl)	$	73.23	$	43.37	$	67.78	$	42.53
WTI oil ($/Bbl)	WTI oil ($/Bbl)	$	66.07	$	27.85	$	61.96	$	37.01	WTI oil ($/Bbl)	$	70.56	$	40.93	$	64.82	$	38.32
NYMEX gas ($/MMBtu)	NYMEX gas ($/MMBtu)	$	2.76	$	1.77	$	2.74	$	1.91	NYMEX gas ($/MMBtu)	$	3.71	$	1.93	$	3.06	$	1.92

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 in each of the four California oil and natural gas basins in which we operate for the ~~three~~ periods presented. See Part I, Item 1 – Financial Statements, Note 6 Assets Held for Sale and ~~six months ended June 30, 2021 and 2020:~~Note 16 Subsequent Events for information regarding the divestiture of our Ventura basin operations.


		Successor	Predecessor	Successor	Predecessor		Successor	Predecessor	Successor	Predecessor
		Three months ended June 30,	Three months ended June 30,	Six months ended June 30,	Six months ended June 30,		Three months ended September 30,	Three months ended September 30,	Nine months ended September 30,	Nine months ended September 30,
		2021	2020	2021	2020		2021	2020	2021	2020
Oil (MBbl/d)	Oil (MBbl/d)					Oil (MBbl/d)
San Joaquin Basin	San Joaquin Basin	39	41	38	44	San Joaquin Basin	40	40	39	42
Los Angeles Basin	Los Angeles Basin	19	27	20	26	Los Angeles Basin	19	22	19	25
Ventura Basin	Ventura Basin	3	2	2	3	Ventura Basin	3	2	3	3

Total	Total	61	70	60	73	Total	62	64	61	70
NGLs (MBbl/d)	NGLs (MBbl/d)					NGLs (MBbl/d)
San Joaquin Basin	San Joaquin Basin	13	13	12	14	San Joaquin Basin	13	14	13	14

Ventura Basin		—	—	1	—

Total	Total	13	13	13	14	Total	13	14	13	14
Natural gas (MMcf/d)	Natural gas (MMcf/d)					Natural gas (MMcf/d)
San Joaquin Basin	San Joaquin Basin	135	148	135	151	San Joaquin Basin	135	142	135	148
Los Angeles Basin	Los Angeles Basin	1	2	1	2	Los Angeles Basin	1	2	1	2
Ventura Basin	Ventura Basin	5	3	5	4	Ventura Basin	5	4	5	4
Sacramento Basin	Sacramento Basin	20	21	20	22	Sacramento Basin	19	20	19	21
Total	Total	161	174	161	179	Total	160	168	160	175

Total Net Production (MBoe/d)	Total Net Production (MBoe/d)	101	112	100	117	Total Net Production (MBoe/d)	102	106	101	113

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~~September 30, 2021, compared to the same period in 2020, decreased by approximately 114 MBoe/d or ~~10%~~4%. For the nine months ended September 30, 2021 compared to the same period in 2020, total daily production decreased by approximately 12 MBoe/d or 11%. The decrease in production largely resulted from limited drilling activity and capital investment during ~~the prior 12 months~~2020 and natural decline rates. This decrease was partially offset by improved operational results from our 2021 drilling program and our acquisition of the working interests in certain joint venture wells held by Macquarie Infrastructure and Real Assets Inc. (MIRA) in the third quarter of 2021. Our production-sharing contracts (PSCs), aswhich are described below, negatively impacted our oil production in the ~~second quarter of~~three and nine months ended September 30, 2021 by approximately ~~five~~1 MBoe/d and approximately 3 MBoe/d, respectively, compared to the same ~~period~~periods 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.

2225

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~~September 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~~The following table presents operating costs after adjusting for excess costs attributable to PSC-type contracts for the three and ~~operating~~nine months ended September 30, 2021:


	Three months ended September 30, 2021				Nine months ended September 30, 2021
	(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs	$	190	$	20.28	$	523	$	19.04
Excess costs attributable to PSC-type contracts	(17)		$	(1.84)	(47)		$	(1.72)
Operating costs, excluding effects of PSC-type contracts(a)	$	173	$	18.44	$	476	$	17.32

(a)Operating costs, excluding effects of PSC-type contracts is a non-GAAP measure. As described above, the ~~effects~~reporting of our PSC-type contracts oncreates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per ~~Boe basis.~~

barrel operating costs. These amounts represent our operating costs after adjusting for this difference.

2326

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~~nine months ended ~~June~~September 30, 2021 and 2020:


		Successor			Predecessor				Successor			Predecessor
		Three months ended June 30,			Three months ended June 30,				Three months ended September 30,			Three months ended September 30,
		2021			2020				2021			2020
		Price		Realization	Price		Realization		Price		Realization	Price		Realization
Oil ($ per Bbl)	Oil ($ per Bbl)							Oil ($ per Bbl)
Brent	Brent	$	69.02		$	33.27		Brent	$	73.23		$	43.37

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%
Realized price without derivative settlements								Realized price without derivative settlements	$	72.89	100%	$	41.83	96%
Effects of derivative settlements								Effects of derivative settlements	(17.47)			0.32
Realized price with derivative settlements								Realized price with derivative settlements	$	55.42	76%	$	42.15	97%

WTI	WTI	$	66.07		$	27.85		WTI	$	70.56		$	40.93

Realized price without hedge		$	68.94	104%	$	30.27	109%
Realized price with hedge		$	54.10	82%	$	30.82	111%
Realized price without derivative settlements								Realized price without derivative settlements	$	72.89	103%	$	41.83	102%
Realized price with derivative settlements								Realized price with derivative settlements	$	55.42	79%	$	42.15	103%

NGLs ($ per Bbl)	NGLs ($ per Bbl)							NGLs ($ per Bbl)
Realized price (% of Brent)	Realized price (% of Brent)	$	44.90	65%	$	21.05	63%	Realized price (% of Brent)	$	53.74	73%	$	25.16	58%
Realized price (% of WTI)	Realized price (% of WTI)	$	44.90	68%	$	21.05	76%	Realized price (% of WTI)	$	53.74	76%	$	25.16	61%

Natural gas	Natural gas							Natural gas
NYMEX ($/MMBtu)	NYMEX ($/MMBtu)	$	2.76		$	1.77		NYMEX ($/MMBtu)	$	3.71		$	1.93

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%
Realized price without derivative settlements ($/Mcf)								Realized price without derivative settlements ($/Mcf)	$	4.66	126%	$	2.22	115%
Effects of derivative settlements								Effects of derivative settlements	(0.02)			0.02
Realized price with derivative settlements ($/Mcf)								Realized price with derivative settlements ($/Mcf)	$	4.64	125%	$	2.24	116%

2427


		Successor			Predecessor				Successor			Predecessor
		Six months ended June 30,			Six months ended June 30,				Nine months ended September 30,			Nine months ended September 30,
		2021			2020				2021			2020
		Price		Realization	Price		Realization		Price		Realization	Price		Realization
Oil ($ per Bbl)	Oil ($ per Bbl)							Oil ($ per Bbl)
Brent	Brent	$	65.06		$	42.12		Brent	$	67.78		$	42.53

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%
Realized price without derivative settlements								Realized price without derivative settlements	$	67.62	100%	$	41.27	97%
Effects of derivative settlements								Effects of derivative settlements	(13.19)			2.00
Realized price with derivative settlements								Realized price with derivative settlements	$	54.43	80%	$	43.27	102%

WTI	WTI	$	61.96		$	37.01		WTI	$	64.82		$	38.32

Realized price without hedge		$	64.89	105%	$	41.02	111%
Realized price with hedge		$	53.91	87%	$	43.76	118%
Realized price without derivative settlements								Realized price without derivative settlements	$	67.62	104%	$	41.27	108%
Realized price with derivative settlements								Realized price with derivative settlements	$	54.43	84%	$	43.27	113%

NGLs ($ per Bbl)	NGLs ($ per Bbl)							NGLs ($ per Bbl)
Realized price (% of Brent)	Realized price (% of Brent)	$	46.75	72%	$	25.18	60%	Realized price (% of Brent)	$	49.20	73%	$	25.17	59%
Realized price (% of WTI)	Realized price (% of WTI)	$	46.75	75%	$	25.18	68%	Realized price (% of WTI)	$	49.20	76%	$	25.17	66%

Natural gas	Natural gas							Natural gas
NYMEX ($/MMBtu)	NYMEX ($/MMBtu)	$	2.74		$	1.91		NYMEX ($/MMBtu)	$	3.06		$	1.92

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%
Realized price without derivative settlements ($/Mcf)								Realized price without derivative settlements ($/Mcf)	$	3.67	120%	$	2.05	107%
Effects of derivative settlements								Effects of derivative settlements	(0.03)			0.06
Realized price with derivative settlements ($/Mcf)								Realized price with derivative settlements ($/Mcf)	$	3.64	119%	$	2.11	110%

Oil — Brent index and realized prices excluding hedge settlements were higher in the three and ~~six~~nine month periods ended ~~June~~September 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~~has been bolstered by the ~~beginning~~re-opening of ~~the pandemic~~economies and ~~have since improved as a result~~easing of ~~easing~~ mobility restrictions related to the COVID-19 pandemic. Prices have also increased due to a rise in domestic demand and lower supply caused by reduced investment in the ~~delayed effects of pandemic-related production curtailments~~U.S. upstream oil and ~~reduced capital investments~~gas sector during 2020 as well as supply management by OPEC ~~members, domestic producers and Russia.~~members.

NGLs — Prices for NGLs increased for the three and ~~six~~nine month periods ended ~~June~~September 30, 2021 compared to the same periods in 2020. ~~In 2020,~~Higher prices are the result of increased 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.~~U.S. and abroad.

Natural Gas — ~~Natural gas index and realized prices were higher in~~For the three and ~~six~~nine months ended ~~June~~September 30, 2021, natural gas prices have increased compared to the same ~~periods~~prior year periods. Increases in ~~2020. The pandemic caused natural gas demand to decline which prompted producers to, in response, reduce production~~pricing – both across the United States and ~~investment. As pandemic-related mobility restrictions~~within California – have been ~~lifted, production increases have thus far failed to keep pace with prompt demand~~driven by strong industrial and ~~seasonal storage requirements.~~

export demand.

2528

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~~nine months ended ~~June~~September 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)~~2020. Energy operating costs consist of purchases of ~~fuel~~natural gas used to generate electricity, purchased electricity and internal costs to ~~produce~~generate electricity used in our operations.

~~(b)~~Non-energy operating costs equal total operating costs less energy ~~operating~~ costs and gas processing costs. ~~Purchases~~However, non-energy operating costs include the costs of ~~fuel~~purchasing natural gas used to generate steam ~~which is then used~~for our steamfloods.


	Successor		Predecessor		Successor		Predecessor
	Three months ended September 30,		Three months ended September 30,		Nine months ended September 30,		Nine months ended September 30,
	2021		2020		2021		2020
Energy operating costs	$	5.49	$	4.25	$	4.97	$	3.81
Gas processing costs	$	0.56	$	0.46	$	0.59	$	0.54
Non-energy operating costs	$	14.23	$	9.81	$	13.48	$	10.50
Operating costs(a)	$	20.28	$	14.52	$	19.04	$	14.85


Field general and administrative expenses(b)	$	0.96	$	1.34	$	0.87	$	1.16
Field depreciation, depletion and amortization(c)	$	5.12	$	8.03	$	5.21	$	8.68
Field taxes other than on income(d)	$	2.67	$	3.40	$	3.02	$	3.10

(a)Operating costs increased in the three and nine months ended September 30, 2021 from the same prior year period primarily as a result of higher downhole maintenance activity in 2021 as well as increased energy costs and natural gas prices as compared to 2020. These increases were partially offset by lower compensation-related costs from headcount reductions and reduced employee benefit costs. The prior year comparative periods include cost savings from measures we took in 2020 to streamline our ~~steamfloods is included in non-energy operating costs.~~

~~(c)As described~~operations and in the months of April and May 2020 we reduced work hours due to the dramatic decrease in commodity prices. For the non-GAAP measure of operating costs, excluding the effects of PSC-type contracts, see Production, Production-Sharing Contractssection, 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. above.

~~(d)~~(b)Excludes corporate general and administrative expenses. Field general and administrative expenses decreased for the three and ~~six~~nine months ended ~~June~~September 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)~~(c)Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant. Field depreciation, depletion and amortization decreased in the three and ~~six~~nine months ended ~~June~~September 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.

(d)Field taxes other than on income decreased in the three months ended September 30, 2021 compared to the same prior year period primarily due to lower ad valorem taxes which are sensitive to commodity prices and generally determined at the beginning of each calendar year. Commodity prices were lower in early 2021 as compared to early 2020.

2629

Consolidated Results of Operations

Three months ended September 30, 2021 vs. 2020

The following table presents our ~~consolidated results of operations~~operating revenues for the three ~~and six~~ months ended ~~June~~September 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~~


	Successor		Predecessor
	Three months ended September 30,		Three months ended September 30,
	2021		2020
(in millions)
Oil, natural gas and NGL sales	$	549	$	312
Net (loss) gain from commodity derivatives	(125)		—
Sales of purchased natural gas	95		50
Electricity sales	65		43
Other revenue	4		4
Total operating revenues	$	588	$	409

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the ~~impact~~effects of ~~settled hedges,~~derivative settlements, were ~~$478~~$549 million for the three months ended ~~June~~September 30, 2021, which is an increase of ~~$233~~$237 million compared to ~~$245~~$312 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			Oil		NGLs		Natural Gas		Total
		(in millions)									(in millions)
Three months ended June 30, 2020		$	193	$	26	$	26	$	245
Three months ended September 30, 2020										Three months ended September 30, 2020	$	246	$	32	$	34	$	312
Changes in realized prices	Changes in realized prices	246		29		22		297		Changes in realized prices	182		36		38		256
Changes in production	Changes in production	(59)		(2)		(3)		(64)		Changes in production	(15)		(1)		(3)		(19)
Three months ended June 30, 2021		$	380	$	53	$	45	$	478
Three months ended September 30, 2021										Three months ended September 30, 2021	$	413	$	67	$	69	$	549

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~~settlements on our commodity derivatives is not included in the table above. Payments for ~~settled hedges~~derivative settlements were ~~$82~~$99 million for the three months ended ~~June~~September 30, 2021 compared to proceeds of $5$2 million for the same period of 2020. Including the effect of ~~settled hedges,~~settlement payments for commodity derivatives, our oil, natural gas and NGL ~~revenue~~sales increased by ~~$146~~$136 million or ~~58%~~43% compared to the same prior-year period.

Net ~~derivative~~ loss from commodity ~~contracts~~derivatives — Net ~~derivative~~ loss from commodity ~~contracts~~derivatives was ~~$265~~$125 million for the three months ended ~~June~~September 30, 2021 ~~compared to a net loss of $4 million~~as shown in the table below. We did not have significant commodity derivatives during the same period of 2020. The non-cash changes in the fair value of our outstanding commodity derivatives resulted from the positions held at the end of each measurement period as well as the relationship between contract prices and the associated forward curves.


		Three months ended June 30,		Three months ended June 30,			Three months ended September 30,		Three months ended September 30,
		2021		2020			2021		2020
(in millions)	(in millions)					(in millions)
Non-cash derivative loss, excluding noncontrolling interest		$	(183)	$	—
Non-cash derivative loss, noncontrolling interest		—		(9)
Non-cash commodity derivative (loss) gain, excluding noncontrolling interest						Non-cash commodity derivative (loss) gain, excluding noncontrolling interest	$	(26)	$	4
Non-cash commodity derivative loss, noncontrolling interest						Non-cash commodity derivative loss, noncontrolling interest	—		(6)
Total non-cash changes	Total non-cash changes	(183)		(9)		Total non-cash changes	(26)		(2)
Net (payments) proceeds on settled commodity derivatives	Net (payments) proceeds on settled commodity derivatives	(82)		5		Net (payments) proceeds on settled commodity derivatives	(99)		2

Net derivative loss from commodity contracts		$	(265)	$	(4)
Net loss from commodity derivatives						Net loss from commodity derivatives	$	(125)	$	—

~~Trading revenue~~

Sales of purchased natural gas — ~~Trading revenue~~Sales of purchased natural gas was ~~$48~~$95 million for the three months ended ~~June~~September 30, 2021, an increase of ~~$34~~$45 million, or ~~243%~~90% from ~~$14~~$50 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~~prices created by ~~a warmer summer in 2021 as compared to 2020.~~increasing demand. Our ~~net margin from~~ natural gas ~~trading activities, after deducting the cost~~sales net of related ~~natural gas~~ purchases ~~was $18~~were $42 million for the three months ended ~~June~~September 30, 2021 compared to $6$15 million for the same period of 2020.

Electricity sales — Electricity sales increased ~~$14~~$22 million to ~~$33~~$65 million in the ~~second~~third quarter of 2021 compared to ~~$19~~$43 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.

The following table presents our operating and non-operating expenses for the three months ended September 30, 2021 and 2020:


	Successor		Predecessor
	Three months ended September 30,		Three months ended September 30,
	2021		2020
(in millions)
Operating expenses
Energy operating costs	$	52	$	41
Gas processing costs	5		5
Non-energy operating costs	133		95
General and administrative expenses	51		64
Depreciation, depletion and amortization	54		89
Asset impairments	25		—
Taxes other than on income	36		42
Exploration expense	2		2
Purchased natural gas expense	53		35
Electricity generation expenses	29		17
Transportation costs	11		10
Accretion expense	13		10
Other operating expenses, net	4		12
Total operating expenses	468		422
Gain on asset divestitures	(2)		—
Operating income (loss)	122		(13)

Non-operating (expenses) income
Reorganization items, net	(1)		66
Interest and debt expense, net	(14)		(28)

Other non-operating expenses, net	—		(32)
Net income (loss) before taxes	$	107	$	(7)

~~Operating~~

Energy operating costs — ~~Operating~~Energy operating costs for the three months ended ~~June~~September 30, 2021 were ~~$169~~$52 million, which was an increase of ~~$42~~$11 million or ~~33%~~27% from ~~$127~~$41 million for the same period of 2020. ~~The~~This increase was primarily ~~attributable~~a result of higher prices for purchased natural gas, which we used to generate electricity for our operations, and for purchased electricity.

Non-energy operating costs — Non-energy operating costs for the three months ended September 30, 2021 were $133 million, which was an increase of $38 million or 40% from $95 million for the same period of 2020. This increase was primarily a result of higher downhole maintenance activity in 2021 which was deferred in 2020 as we shut-in ~~wells.~~wells and surface maintenance activity. Additionally, non-energy operating costs increased in 2021 due to higher ~~energy costs and~~prices for purchased natural gas ~~prices as compared~~which we use to ~~2020.~~generate steam for our steamfloods. 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~~and reduced employee benefits in the second quarter of 2021. Our ~~second~~third quarter 2020 results reflect cost savings for ~~reduced work hours and reduced management salaries~~streamlining our operations 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~~this commodity which we also produce.

General and administrative expenses — Our general and administrative (G&A) expenses were ~~$48~~$51 million for the three months ended ~~June~~September 30, 2021, which was a decrease of ~~$21~~$13 million from ~~$69~~$64 million for the three months ended ~~June~~September 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 non-cash 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~~$35 million to $54 million in the ~~second~~third quarter of 2021 compared to ~~$88~~$89 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~~Asset impairments — ~~Natural gas purchases related to trading activities were $30~~We recorded an impairment charge of $25 million for the three months ended ~~June~~September 30, 2021 related to the write-down of a commercial office building located in Bakersfield, California to fair market value. The decline in asset value primarily relates to limited demand for office space of this size and type in the Bakersfield market and general trends in commercial real estate due to the COVID-19 pandemic. No impairment charges were recorded for the same period in 2020. See Part I, Item 1 – Financial Statements, Note 13 Asset Impairments for additional information.

Purchased natural gas expense — Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. This expense amounted to $53 million for the three months ended September 30, 2021, which was an increase of ~~$22~~$18 million or ~~275%~~51% from $8$35 million for the same period in 2020. The ~~change~~increase was predominantly the result of higher ~~activity levels and~~natural gas prices.

~~Other~~Electricity generation expenses ~~net~~ — ~~Other~~Electricity generation expenses ~~net was $23~~increased from $17 million for the three months ended ~~June~~September 30, 2020 to $29 million in the same period of 2021. The increase was primarily a result of higher prices for natural gas used in electricity generation.

Reorganization items, net — Reorganization items, net decreased by $67 million to $1 million of expense for the three months ended September 30, 2021 ~~which was a decrease~~from $66 million of ~~$14 million from $37 million~~income during the same period of 2020. ~~The decrease was largely~~We recognized $66 million of income in the third quarter of 2020 primarily due to ~~a one-time payment~~the write-off of ~~$20 million made in connection with an expiring pipeline delivery contract~~the unamortized balance of deferred gain and issuance costs on our long-term debt at the time of filing our bankruptcy petition on July 15, 2020. The gain was partially offset by ~~a $3 million property tax refund.~~legal, professional and other fees, including debtor-in-possession financing costs, all of which related to our bankruptcy proceedings.

Interest and debt expense, net — Interest and debt expense, net decreased ~~$72 million~~ to ~~$13~~$14 million in the ~~second~~third quarter of 2021 compared to ~~$85~~$28 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~~bankruptcy on October 27, 2020. There were no amounts drawn on our Revolving Credit Facility ~~and had no balance drawn~~ during the ~~quarter.~~three months ended September 30, 2021. 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, net — Other non-operating expense, net decreased ~~$45~~$32 million to ~~$2 million~~zero for the three months ended ~~June~~September 30, ~~2021 compared to $47 million in the same period for 2020.~~2021. The decrease was primarily due to the significant legal, professional and other fees incurred in preparation for our Chapter 11 filing ~~on July 15,~~in 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~~Nine Months Ended September 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 7Joint Ventures~~ ~~in our~~vs. 2020 ~~Annual Reportfor additional information on the settlement terms of the Ares JV.~~

~~Six Months Ended June~~The following table presents our operating revenues for the nine months ended September 30, 2021 ~~vs. 2020~~and 2020:


	Successor		Predecessor
	Nine months ended September 30,		Nine months ended September 30,
	2021		2020
(in millions)
Oil, natural gas and NGL sales	$	1,459	$	987
Net (loss) gain from commodity derivatives	(603)		75
Sales of purchased natural gas	241		109
Electricity sales	131		75
Other revenue	27		12
Total operating revenues	$	1,255	$	1,258

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the ~~impact~~effects of ~~settled hedges,~~derivative settlements, were ~~$910~~$1,459 million for the ~~six~~nine months ended ~~June~~September 30, 2021, which is an increase of ~~$235~~$472 million compared to ~~$675~~$987 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			Oil		NGLs		Natural Gas		Total
		(in millions)									(in millions)
Six months ended June 30, 2020		$	549	$	62	$	64	$	675
Nine months ended September 30, 2020										Nine months ended September 30, 2020	$	795	$	94	$	98	$	987
Changes in realized prices	Changes in realized prices	319		53		39		411		Changes in realized prices	508		89		78		675
Changes in production	Changes in production	(157)		(8)		(11)		(176)		Changes in production	(179)		(9)		(15)		(203)
Six months ended June 30, 2021		$	711	$	107	$	92	$	910
Nine months ended September 30, 2021										Nine months ended September 30, 2021	$	1,124	$	174	$	161	$	1,459

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~~settlements on our commodity derivatives is not included in the table above. Payments for ~~settled hedges~~derivative settlements were ~~$121~~$220 million for the ~~six~~nine months ended ~~June~~September 30, 2021 compared to proceeds of ~~$103~~$105 million, including $63 million of proceeds from commodity derivative contracts sold prior to maturity, in the first quarter of 2020. Including the effect of ~~settled hedges,~~settlement payments for commodity derivatives, our oil, natural gas and NGL ~~revenue~~sales increased by ~~$11~~$147 million or 1%13% compared to the same prior-year period.

Net ~~derivative~~(loss) gain from commodity derivatives — Net loss from commodity ~~contracts~~ ~~— Net derivative loss from commodity contracts~~derivatives was ~~$478~~$603 million for the ~~six~~nine months ended ~~June~~September 30, 2021 compared to a net gain of $75 million in the same period of ~~2020.~~2020 as shown in the table below. The non-cash changes in the fair value of our outstanding commodity derivatives resulted from the positions held at the end of each measurement 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


	Nine months ended September 30,		Nine months ended September 30,
	2021		2020
(in millions)
Non-cash commodity derivative loss, excluding noncontrolling interest	$	(383)	$	(31)
Non-cash commodity derivative gain, noncontrolling interest	—		1
Total non-cash changes	(383)		(30)
Net (payments) proceeds on settled commodity derivatives	(220)		42
Net proceeds on commodity derivative contracts sold prior to maturity	—		63
Net (loss) gain from commodity derivatives	$	(603)	$	75

~~Trading revenue~~Sales of purchased natural gas — ~~Trading revenue was $146~~Sales of purchased natural gas were $241 million for the ~~six~~nine months ended ~~June~~September 30, 2021, an increase of ~~$87~~$132 million, or ~~147%~~121% from ~~$59~~$109 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~~prices created by ~~colder winter temperatures and a warmer summer~~increased demand in 2021 as compared to 2020. Our ~~net margin from~~ natural gas ~~trading activities, after deducting the cost~~sales net of related ~~natural gas~~ purchases ~~was $55~~were $97 million for the ~~six~~nine months ended ~~June~~September 30, 2021 compared to ~~$27~~$42 million for the same period of 2020.

Electricity sales — Electricity sales increased ~~$34~~by $56 million to ~~$66~~$131 million in the first ~~half~~nine months of 2021 compared to ~~$32~~$75 million in the same period of 2020. Electricity sales increased in the first ~~half~~nine months of 2021 from the prior year period as a result of higher ~~pricing resulting from~~natural gas prices due in part to reduced hydroelectric generation in ~~California as well as increased natural gas prices.~~California. In the first ~~half~~nine months of 2020, sales volumes were also lower from planned maintenance and an outage at the Elk Hills power plant.

~~Operating costs~~Other revenue — ~~Operating costs for~~Other revenue increased by $15 million to $27 million in the ~~six~~first nine months ~~ended June 30,~~of 2021 ~~were $333~~compared to $12 million ~~which was an increase of $14 million or 4% from $319 million for~~in the same period of 2020. The increase was primarily ~~attributable~~driven by higher revenues from wet gas and processing fee income caused by higher natural gas prices.

The following table presents our operating and non-operating expenses for the nine months ended September 30, 2021 and 2020:


	Successor		Predecessor
	Nine months ended September 30,		Nine months ended September 30,
	2021		2020
(in millions)
Operating expenses
Energy operating costs	$	137	$	118
Gas processing costs	16		17
Non-energy operating costs	370		325
General and administrative expenses	147		193
Depreciation, depletion and amortization	160		296
Asset impairments	28		1,736
Taxes other than on income	113		121
Exploration expense	6		9
Purchased natural gas expense	144		67
Electricity generation expenses	70		47
Transportation costs	37		31
Accretion expense	39		30
Other operating expenses, net	31		45
Total operating expenses	1,298		3,035
Gain on asset divestitures	(4)		—
Operating loss	(39)		(1,777)

Non-operating (expenses) income
Reorganization items, net	(5)		66
Interest and debt expense, net	(40)		(200)
Net (loss) gain on early extinguishment of debt	(2)		5
Other non-operating expenses, net	(3)		(93)
Net loss before taxes	$	(89)	$	(1,999)

Energy operating costs — Energy operating costs for the nine months ended September 30, 2021 were $137 million, which was an increase of $19 million or 16% from $118 million for the same period of 2020. This increase was primarily a result of higher prices for purchased natural gas, which we used to generate electricity for our operations, and for purchased electricity.

Non-energy operating costs — Non-energy operating costs for the nine months ended September 30, 2021 were $370 million, which was an increase of $45 million or 14% from $325 million for the same period of 2020. This increase was primarily a result of higher downhole maintenance activity in 2021 which was deferred in 2020 as we shut-in ~~wells.~~wells and surface maintenance activity. Additionally, non-energy operating costs increased in 2021 due to higher ~~energy costs and~~prices for natural gas, ~~prices as compared~~which we use to ~~2020. These~~generate steam for our steamfloods. Partially offsetting these increases were ~~partially offset by~~ lower compensation-related costs from ~~streamlining our operations, including~~ headcount reductions in ~~the second half of~~late 2020 and ~~in the first quarter of~~early 2021 ~~as well as benefit reductions~~and reduced employee benefits in the second quarter of 2021. Although higher natural gas ~~and electricity~~ prices ~~increase~~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~~this commodity which we also produce.

General and administrative expenses — Our general and administrative (G&A) expenses were ~~$96~~$147 million for the ~~six~~nine months ended ~~June~~September 30, 2021, which was a decrease of ~~$33~~$46 million from ~~$129~~$193 million for the ~~six~~nine months ended ~~June~~September 30, 2020. The decrease in G&A expenses ~~were~~was 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 an increase in non-cash 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~~$136 million to ~~$106~~$160 million in the first ~~half~~nine months of 2021 compared to ~~$207~~$296 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~~nine months ended ~~June~~September 30, 2021 were $3$28 million ~~for~~including a write-down of commercial office space in Bakersfield, California to fair value and the ~~impairment~~write-off of capitalized costs related to projects which were abandoned. The decline in value of the commercial office building primarily relates to limited demand for office space of this size and type in the Bakersfield market and general trends in commercial real estate due to the COVID-19 pandemic. 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 1213 Asset Impairments for additional information.

~~Trading costs~~Purchased natural gas expense — ~~Natural~~Purchased natural gas ~~purchases related~~expense relates to ~~trading activities were $91~~natural gas acquired from third parties in connection with certain of our marketing activities. This expense amounted to $144 million for the ~~six~~nine months ended ~~June~~September 30, 2021, which was an increase of ~~$59~~$77 million or ~~184%~~115% from ~~$32~~$67 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.~~prices.

Electricity ~~cost of sales~~generation expenses — Electricity cost of sales increased from ~~$30~~$47 million in the first ~~half~~nine months of 2020 to ~~$41~~$70 million in the same period of 2021. The increase was primarily a result of higher pricing on purchased natural ~~gas purchases.~~gas.

Other operating expenses, net — Other expenses, net was $31 million for the nine months ended September 30, 2021, which was a decrease of $14 million from $45 million during the same period of 2020. The first nine months of 2020 included a one-time payment of $20 million made in connection with an expiring pipeline delivery contract and $7 million related to an outage at the Elk Hills power plant. The first nine months of 2021 included $15 million in severance costs.

Reorganization items, net — Reorganization items, net was $5 million of expense for the nine months ended September 30, 2021 which was a decrease of $71 million from $66 million of income during the same period of 2020. We recognized $66 million of income in the third quarter of 2020 primarily due to the write-off of the unamortized balance of our deferred gain and issuance costs on our long-term debt at the time of filing our bankruptcy petition on July 15, 2020 which was partially offset by legal, professional and other fees, including debtor-in-possession financing costs, all of which related to our bankruptcy proceedings.

Interest and debt expense, net — Interest and debt expense, net decreased ~~$146~~$160 million to ~~$26~~$40 million in the first ~~half~~nine months of 2021 compared to ~~$172~~$200 million in the same period of 2020 primarily due to a decrease in our overall level of debt upon our emergence from ~~bankruptcy.~~bankruptcy on October 27, 2020. Additionally, in the first quarter of 2021, we ~~reduced the amount drawn on~~paid off our Revolving Credit Facility and had no balance drawn induring either the second or third 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, net — Other non-operating expense, net decreased ~~$60~~$90 million to $1$3 million for the ~~six~~nine months ended ~~June~~September 30, 2021 compared to ~~$61~~$93 million in the same period for 2020. The higher expense in the first ~~half~~nine months 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 7Joint 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~~September 30, 2021, our operating cash flow increased ~~194%~~279%, or ~~$262~~$134 million, to ~~$127~~$182 million from ~~$(135)~~$48 million in the same prior period of 2020. For the ~~six~~nine months ended ~~June~~September 30, 2021, our operating cash flow increased ~~195%~~223%, or ~~$181~~$315 million, to ~~$274~~$456 million from ~~$93~~$141 million in the same period of 2020.

The increase in operating cash flow for both the three and nine months ended September 30, 2021 primarily relates to higher average realized prices ~~with hedge~~(including the effects of settlements on our commodity derivatives) in 2021 compared to the same prior-year ~~period which is~~periods. Average realized prices increased primarily due to the economic recovery ~~in 2021~~ as COVID-19 ~~driven~~related 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 the third quarter of 2021, we purchased $24 million of greenhouse gas allowances of which $6 million was for our fourth quarter of 2021 obligation and $18 million was a prepayment for our 2022 compliance obligation. This prepayment is included 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~~on our condensed consolidated statements of ~~higher trade accounts receivable balances as well as higher payables related to derivatives~~cash flows for the three and ~~increased activity.~~nine months ended September 30, 2021.

Cash flows from investing activities — Our net cash used in investing activities increased ~~$28~~$87 million ~~or 187%~~ from ~~$15~~$1 million for the three months ended ~~June~~September 30, 2020 to ~~$43~~$88 million for the same period in 2021. Our net cash used in investing activities increased ~~$36~~$123 million ~~or 133%~~ from ~~$27~~$28 million for the ~~six~~nine months ended ~~June~~September 30, 2020 to ~~$63~~$151 million for the same period in 2021.

The increased use of cash for investing activities in 2021 primarily relates to higher capital investment and our acquisition of working interests in certain joint venture wells held by MIRA. Investing activities in 2020 included proceeds of $41 million related to a sale of royalty interests and a non-core asset in the nine months ended September 30, 2020. Proceeds of $13 million from non-core asset sales for the nine months ended September 30, 2021 primarily related to the sale of unimproved land. The table below summarizes net cash used in investing activities for the three and ~~six~~nine months ended ~~June~~September 30, 2021 and 2020 (in millions):


		Successor		Predecessor		Successor		Predecessor			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			Three months ended September 30, 2021		Three Months Ended September 30, 2020		Nine months ended September 30, 2021		Nine Months Ended September 30, 2020
(in millions)	(in millions)									(in millions)
Capital investments	Capital investments	$	(50)	$	(3)	$	(77)	$	(33)	Capital investments	$	(51)	$	(4)	$	(128)	$	(37)
Changes in capital investment accruals	Changes in capital investment accruals	8		(9)		13		(28)		Changes in capital investment accruals	5		3		18		(25)
Proceeds from divestitures	Proceeds from divestitures	—		—		2		41		Proceeds from divestitures	11		—		13		41
Acquisitions										Acquisitions	(53)		—		(53)		—
Other	Other	(1)		(3)		(1)		(7)		Other	—		—		(1)		(7)
Net cash used in investing activities	Net cash used in investing activities	$	(43)	$	(15)	$	(63)	$	(27)	Net cash used in investing activities	$	(88)	$	(1)	$	(151)	$	(28)

Cash flows from financing activities — Our net cash used in financing activities was ~~$63~~$56 million for the three months ended ~~June~~September 30, 2021 compared to net cash ~~provided by~~used in financing activities of ~~$199~~$51 million orfor the same period of 2020. Our net cash used in financing activities was ~~$88~~$144 million for the ~~six~~nine months ended ~~June~~September 30, 2021 compared to net cash ~~provided by~~used in financing activities of ~~$43~~$8 million for the same period of 2020.

Financing activities for the three and nine months ended ~~June~~September 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~~cash outflows related to debt transactions for the ~~three and six~~nine months ended ~~June~~September 30, 2020 ~~primarily~~ included $733 million in net borrowings under our debtor-in-possession facilities partially offset by $518 million in net repayments on our then outstanding revolving credit facility, ~~in place~~$100 million for the repayment of our 2020 Senior Notes at ~~that time.~~maturity, $25 million for debtor-in-possession financing costs and $3 million for open market purchases of our then outstanding Second Lien Notes. The table below summarizes net cash used by financing activities for the three and ~~six~~nine months ended ~~June~~September 30, 2021 and 2020 (in millions):


		Successor		Predecessor		Successor		Predecessor			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			Three months ended September 30, 2021		Three Months Ended September 30, 2020		Nine months ended September 30, 2021		Nine Months Ended September 30, 2020
(in millions)	(in millions)									(in millions)
Debt transactions, net	Debt transactions, net	$	(1)	$	223	$	(12)	$	113	Debt transactions, net	$	—	$	(23)	$	(12)	$	87
Debt repurchases		—		—		—		(3)
Distributions to noncontrolling interest holders, net	Distributions to noncontrolling interest holders, net	(17)		(24)		(31)		(66)		Distributions to noncontrolling interest holders, net	(19)		(28)		(50)		(94)
Repurchases of common stock	Repurchases of common stock	(45)		—		(45)		—		Repurchases of common stock	(39)		—		(84)		—
Proceeds from warrants exercised										Proceeds from warrants exercised	2		—		2		—
Other	Other	—		—		—		(1)		Other	—		—		—		(1)
Net cash (used in) provided by financing activities		$	(63)	$	199	$	(88)	$	43
Net cash used in financing activities										Net cash used in financing activities	$	(56)	$	(51)	$	(144)	$	(8)

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~~nine months of 2021 was for capital investment, distributions to a noncontrolling interest holder, acquisition of working interests from MIRA and repurchases of our common stock.

In November 2021, the borrowing base under our Revolving Credit Facility was reaffirmed at $1.2 billion.

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~~expect to 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, commodity prices, the amount and type of our capital spend, cost structure and activity levels. Potential legislation could ~~also limit~~change key provisions of the existing U.S. corporate income tax ~~incentives for fossil fuels.~~regime and it is uncertain whether some or all of the legislative proposals will be enacted. We do not currently expect the proposed modifications will materially impact our income tax liability. 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~~September 30,
	2021
	(in millions)
Cash	$	~~151~~189
Revolving Credit Facility:
Borrowing capacity~~(a)~~	492
Outstanding letters of credit	~~(125)~~(133)
Availability	$	~~367~~359

Liquidity	$	~~518~~548

~~(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, Note5 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.

Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and 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~~nine months ended ~~June~~September 30, 2021.

See Part I, Item 1 – Financial Statements, Note 89 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of ~~June~~September 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~~In the ~~full year~~second quarter of 2021, ~~capital program to $170 million to $190 million reflecting a reallocation of~~we reallocated drilling capital to downhole maintenance activities which ~~provide efficiencies and faster payouts. The current~~reduced our full year outlook to $170 million – $190 million. Success of the drilling program to date, along with the rise in commodity prices, resulted in the addition of a drilling rig in the fourth quarter of 2021 that was planned for 2022. As a result, we expect our full year capital program ~~anticipates that we will maintain a consistent level of investment throughout the remainder of the year. If commodity prices decline significantly~~to range from ~~current levels, we may need to decrease the size of our capital program in response to market conditions.~~$180 – $200 million.

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~~Nine months ended ~~June~~September 30, 2021
	(in millions)
Drilling	$90110 - ~~$100~~$120	$4173
Capital workovers	3525 - 4030	1725
Infrastructure, corporate and other	45 - 50	1930
Total	$~~170~~180 - ~~$190~~$200	$77128

Regulatory Update

In April 2021, Governor Gavin Newsom signed an executive order directing the California Department of Conservation’s Geologic Energy Management Division (CalGEM) 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~~CalGEM published the proposed rule to end the issuance of new permits for well stimulation treatments. Since the Governor’s announcement, CalGem has not issued any approvals 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.

In October 2021, CalGEM released for public comment a draft rule to update its public health regulations. Among other changes, the draft includes a proposed setback of 3,200 feet for new wells with new surface locations from sensitive receptors, such as residences, schools and health care facilities. The draft is subject to public comment and the rulemaking process. It is anticipated that a version of the draft rule will be adopted in the next 12 to 24 months. We expect little to no impact on our long-term development plans because our development strategy does not rely on a significant number of new wells with new surface locations in affected setback areas.

Dividends

Share Repurchase Program

~~In August 2021, our~~Our Board of Directors authorized ~~an increase to the~~a Share Repurchase Program ~~by $100 million~~for up to $250 million through March 31, 2022. As of September 30, 2021, we repurchased 2.6 million shares of our common stock, at an average price of $32.39 per share, through either open market purchases or a Rule 10b5-1 plan at an aggregate cost of $84 million. Shares repurchased were held as treasury stock as of September 30, 2021. On November 11, 2021, our Board of Directors extended the time period for our Share Repurchase Program through June 30, 2022.

3439

Divestitures

InAfter 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 ifquarter-end, closings for 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.

~~The~~ sale of our Ventura basin operations ~~met~~occurred with respect to the ~~criteria for~~majority of the basin's 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 transactionssubsequent closings are expected to ~~close~~occur in the ~~second half of 2021.~~following quarters. See Part I, Item 1 – Financial Statements, Note 6 Assets Held for Sale for more information regarding this transaction.

Acquisitions and Joint Ventures

In ~~April 2017,~~the third quarter of 2021, we ~~entered into a~~completed the wind-up of our development joint venture (JV) with MIRA and our 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.~~ Benefit Street Partners (BSP).

In August 2021, we purchased MIRA’s entire working interest share in the conveyed assets for $53 million, before purchase price adjustments and transaction costs. Prior to the acquisition, our consolidated results reflect only our 10% working interest share in the productive wells. ~~The acquisition of MIRA's working interest would have added oil production of approximately 2 MBoe/d to~~See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7Joint Ventures in our ~~consolidated results~~ 2020 Annual Reportfor ~~the first half of 2021.~~additional information on our MIRA JV.

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~~September 2021, BSP's 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~~JV was automatically redeemed in full ~~with no additional payment. For~~under the ~~first half~~terms of ~~2021,~~the joint venture agreement. Prior to the redemption, we ~~distributed $31 million to BSP. We anticipate our remaining~~made aggregate distributions to BSP of $50 million in 2021 which reduced noncontrolling interest on our condensed consolidated balance sheet and was recorded as a financing cash outflow on our condensed consolidated statements of cash flows for the ~~second half of 2021 will approximate $20 million.~~nine months ended September 30, 2021. 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.

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~~September 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. In September 2021, we accepted the indemnification claim from Oxy and will be challenging the order from BSEE.

See Part I, Item 1 – Financial Statements, Note 78 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.

3641

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. These statements are not promises or guarantees of future conduct, performance or policy and 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~~Therefore, the actual conduct of our activities, including development, implementation, or continuation of any carbon capture and ~~do not warrant their accuracy~~storage programs or ~~completeness.~~ other initiatives or efforts discussed or forecasted in this report or in the future in connection with updates issued regarding these programs, initiatives and efforts, may differ materially in the future.

Factors (but not necessarily all the factors) that could cause results to differ include:

•our ability to execute our business plan ~~post-emergence;~~post-emergence, including our ability to finance and implement our carbon storage program;

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

•global socio-demographic and economic trends and technological innovations;

•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;

•changes in our dividend policy and our ability to declare future dividends;

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

•our ability to successfully gather and verify data regarding our environmental impacts and initiatives;

•the compliance of various third parties with our policies and procedures and legal requirements as well as contracts we enter into in connection with our climate-related initiatives;

•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;

•climate-related conditions and weather events

•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.

This report may also contain information from third party sources. This data may involve a number of assumptions and limitations, and we have not independently verified them and do not warrant the accuracy or completeness of such third-party information.

Item 3Quantitative and Qualitative Disclosures About Market Risk

For the three and ~~six~~nine months ended ~~June~~September 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~~September 30, 2021, we had net liabilities of ~~$421~~$418 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~~September 30, 2021, refer to Part I, Item 1 – Financial Statements, Note 89 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~~nine months ended ~~June~~September 30, 2021 or ~~the three months ended June~~September 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~~September 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~~September 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~~September 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~~September 30, 2021 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

3944

PART II OTHER INFORMATION

Item 1Legal Proceedings

For additional information regarding legal proceedings, see Item 1 – Financial Statements, Note 78 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~~nine months ended ~~March 31,~~September 30, 2021.

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds

~~In May 2021, our~~Our Board of Directors authorized a Share Repurchase Program to acquire up to ~~$150~~$250 million of our common stock through ~~March 31,~~June 30, 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~~September 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 $ —


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)
July 1, 2021 - July 31, 2021	—	$	—	—	$	—
August 1, 2021 - August 31, 2021	710,270	$	29.90	710,270	—
September 1, 2021 - September 30, 2021	441,326	$	39.08	441,326	—
Total	1,151,596			1,151,596	$	—

(a)The dollar value of shares that may yet be purchased under the Share Repurchase Program totaled ~~$105~~$166 million as of ~~June~~September 30, ~~2021 and is currently $205 million.~~2021.

Item 5 Other Disclosures

None.

4045

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

4146

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,~~November 12, 2021	/s/ Noelle M. Repetti
		Noelle M. Repetti
		Vice President and Controller
		(Principal Accounting Officer)

4247


	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	0	%	0	%
Forecast period (in years)	2 - 3		3