California Resources Corp - Quarter Report: 2022 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2022

☐ 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.)

1 World Trade Center, Suite 1500

Long Beach, California 90831

(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, 2022 was 75,375,633.

California Resources Corporation and Subsidiaries

Table of Contents


	Page
Part I
Item 1	Financial Statements (unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements of Comprehensive Income (Loss)	6
	Condensed Consolidated Statements of Stockholders' Equity	7
	Condensed Consolidated Statements of Cash Flows	9
	Notes to the Condensed Consolidated Financial Statements	10
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
	General	22
	Joint Ventures	22
	Dividends	22
	Share Repurchase Program	23
	Divestitures and Acquisitions	23
	Business Environment and Industry Outlook	23
	Regulatory Update	24
	Production	25
	Prices and Realizations	27
	Statements of Operations Analysis	29
	Liquidity and Capital Resources	35
	2022 Capital Program	36
	Lawsuits, Claims, Commitments and Contingencies	38
	Critical Accounting Estimates and Significant Accounting and Disclosure Changes	38
	Forward-Looking Statements	39
Item 3	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4	Controls and Procedures	41

Part II
Item 1	Legal Proceedings	42
Item 1A	Risk Factors	42
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 5	Other Disclosures	42
Item 6	Exhibits	43

GLOSSARY AND SELECTED ABBREVIATIONS

The following are abbreviations and definitions of certain terms used within this Form 10-Q:

•ABR - Alternate base rate.

•ASC - Accounting Standards Codification.

•ARO - Asset retirement obligation.

•Bbl - Barrel.

•Bbl/d - Barrels per day.

•Bcf - Billion cubic feet.

•Bcfe - Billion cubic feet of natural gas equivalent using the ratio of one barrel of oil, condensate, or NGLs converted to six thousand cubic feet of natural gas.

•Boe - We convert natural gas volumes to crude oil equivalents using a ratio of six thousand cubic feet (Mcf) to one barrel of crude oil equivalent based on energy content. This is a widely used conversion method in the oil and gas industry.

•Boe/d - Barrel of oil equivalent per day.

•Btu - British thermal unit.

•CalGEM - California Geologic Energy Management Division.

•CCS - Carbon capture and storage.

•CO2 - Carbon dioxide.

•DD&A - Depletion, depreciation, and amortization.

•EOR - Enhanced oil recovery.

•EPA - United States Environmental Protection Agency.

•ESG - Environmental, social and governance.

•E&P - Exploration and production.

•FEED - Front-end engineering design.

•Full-Scope Net Zero - Achieving permanent storage of captured or removed carbon emissions in a volume equal to all of our scope 1, 2 and 3 emissions by 2045.

•GAAP - United States Generally Accepted Accounting Principles.

•GHG - Greenhouse gases.

•JV - Joint venture.

•LCFS - Low Carbon Fuel Standard.

•LIBOR - London Interbank Offered Rate.

•MBbl - One thousand barrels of crude oil, condensate or NGLs.

•MBbl/d - One thousand barrels per day.

•MBoe/d - One thousand barrels of oil equivalent per day.

•MBw/d - One thousand barrels of water per day

•Mcf - One thousand cubic feet of natural gas equivalent, with liquids converted to an equivalent volume of natural gas using the ratio of one barrel of oil to six thousand cubic feet of natural gas.

•MHp - One thousand horsepower.

•MMBbl - One million barrels of crude oil, condensate or NGLs.

•MMBoe - One million barrels of oil equivalent.

•MMBtu - One million British thermal units.

•MMcf/d - One million cubic feet of natural gas per day.

•MW - Megawatts of power.

•NGLs - Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as purity products such as ethane, propane, isobutane and normal butane, and natural gasoline.

•NYMEX - The New York Mercantile Exchange.

•OPEC - Organization of the Petroleum Exporting Countries.

•OPEC+ - OPEC and together with Russia and other allied producing countries

•PHMS - Pipeline and Hazardous Materials Safety Administration.

•Proved developed reserves - Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

•Proved reserves - The estimated quantities of natural gas, NGLs, and oil that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations.

•Proved undeveloped reserves - Proved reserves that are expected to be recovered from new wells on undrilled acreage that are reasonably certain of production when drilled or from existing wells where a relatively major expenditure is required for recompletion.

•PSCs - Production-sharing contracts.

•PV-10 - Non-GAAP financial measure and represents the year-end present value of estimated future cash flows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum and using SEC Prices. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.

•SDWA - Safe Drinking Water Act.

•SEC - United States Securities and Exchange Commission.

•SEC Prices - The unweighted arithmetic average of the first day-of-the-month price for each month within the year used to determine estimated volumes and cash flows for our proved reserves.

•SOFR - Secured overnight financing rate as administered by the Federal Reserve Bank of New York.

•Standardized measure - The year-end present value of after-tax estimated future cash flows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum and using SEC Prices. Standardized measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing, costs and discount assumptions.

•Working interest - The right granted to a lessee of a property to explore for and to produce and own oil, natural gas or other minerals in-place. A working interest owner bears the cost of development and operations of the property.

•WTI - West Texas Intermediate.

PART I FINANCIAL INFORMATION

Item 1Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of June 30, 2022 and December 31, 2021

(in millions, except share data)



	June 30,		December 31,
	2022		2021
CURRENT ASSETS
Cash	$	324	$	305
Trade receivables	340		245
Inventories	57		60
Assets held for sale	3		22
Other current assets	127		121
Total current assets	851		753
PROPERTY, PLANT AND EQUIPMENT	3,016		2,845
Accumulated depreciation, depletion and amortization	(341)		(246)
Total property, plant and equipment, net	2,675		2,599
DEFERRED TAX ASSET	367		396
OTHER NONCURRENT ASSETS	125		98
TOTAL ASSETS	$	4,018	$	3,846


CURRENT LIABILITIES



Accounts payable	290		266
Liabilities associated with assets held for sale	2		21
Fair value of derivative contracts	514		270
Accrued liabilities	402		297

Total current liabilities	1,208		854
NONCURRENT LIABILITIES
Long-term debt, net	591		589

Fair value of derivative contracts	133		132
Asset retirement obligations	409		438
Other long-term liabilities	160		145



STOCKHOLDERS' EQUITY
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at June 30, 2022 and December 31, 2021	—		—
Common stock (200,000,000 shares authorized at $0.01 par value) (83,389,522 and 83,389,210 shares issued; 75,375,633 and 79,299,222 shares outstanding at June 30, 2022 and December 31, 2021)	1		1
Treasury stock (8,013,889 shares held at cost at June 30, 2022 and 4,089,988 shares held at cost at December 31, 2021)	(315)		(148)
Additional paid-in capital	1,296		1,288
Retained earnings	463		475
Accumulated other comprehensive income	72		72


Total stockholders' equity	1,517		1,688
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	4,018	$	3,846

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

For the three and six months ended June 30, 2022 and 2021

(dollars in millions, except per share data)



	Three months ended June 30,				Six months ended June 30,
	2022		2021		2022		2021
REVENUES
Oil, natural gas and NGL sales	$	718	$	478	$	1,346	$	910
Net loss from commodity derivatives	(100)		(265)		(662)		(478)
Sales of purchased natural gas	75		48		107		146
Electricity sales	49		33		83		66
Other revenue	5		10		26		23
Total operating revenues	747		304		900		667

OPERATING EXPENSES
Operating costs	190		169		372		333
General and administrative expenses	56		48		104		96
Depreciation, depletion and amortization	50		54		99		106
Asset impairments	2		—		2		3
Taxes other than on income	42		37		76		77
Exploration expense	1		2		2		4
Purchased natural gas expense	67		30		88		91
Electricity generation expenses	33		17		57		41
Transportation costs	12		14		24		26
Accretion expense	11		13		22		26
Other operating expenses, net	9		10		23		27
Total operating expenses	473		394		869		830
Net gain on asset divestitures	4		—		58		—

OPERATING INCOME (LOSS)	278		(90)		89		(163)

NON-OPERATING (EXPENSES) INCOME
Reorganization items, net	—		(2)		—		(4)
Interest and debt expense, net	(13)		(13)		(26)		(26)
Net loss on early extinguishment of debt	—		—		—		(2)
Other non-operating income (expenses), net	1		(2)		2		(1)
INCOME (LOSS) BEFORE INCOME TAXES	266		(107)		65		(196)
Income tax provision	(76)		—		(50)		—
NET INCOME (LOSS)	190		(107)		15		(196)



Net income attributable to noncontrolling interests	—		(4)		—		(9)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	190	$	(111)	$	15	$	(205)

Net income (loss) attributable to common stock per share
Basic	$	2.48	$	(1.34)	$	0.19	$	(2.46)
Diluted	$	2.41	$	(1.34)	$	0.19	$	(2.46)

Weighted-average common shares outstanding
Basic	76.7		83.1		77.6		83.2
Diluted	78.8		83.1		79.6		83.2

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Comprehensive Income (Loss)

For the three and six months ended June 30, 2022 and 2021

(in millions)



	Three months ended June 30,				Six months ended June 30,
	2022		2021		2022		2021
Net income (loss)	$	190	$	(107)	$	15	$	(196)
Net income attributable to noncontrolling interests	—		(4)		—		(9)



Comprehensive loss attributable to common stock	$	190	$	(111)	$	15	$	(205)

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Stockholders' Equity

For the three and six months ended June 30, 2022

(in millions)


	Three months ended June 30, 2022
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, March 31, 2022	$	1	$	(219)	$	1,293	$	286	$	72	$	1,433
Net income	—		—		—		190		—		190

Share-based compensation	—		—		3		—		—		3



Repurchases of common stock	—		(96)		—		—		—		(96)

Cash dividends ($0.17 per share)	—		—		—		(13)		—		(13)

Balance, June 30, 2022	$	1	$	(315)	$	1,296	$	463	$	72	$	1,517


	Six months ended June 30, 2022
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, December 31, 2021	$	1	$	(148)	$	1,288	$	475	$	72	$	1,688
Net income	—		—		—		15		—		15

Share-based compensation	—		—		8		—		—		8



Repurchases of common stock	—		(167)		—		—		—		(167)

Cash dividends ($0.17 per share)	—		—		—		(27)		—		(27)

Balance, June 30, 2022	$	1	$	(315)	$	1,296	$	463	$	72	$	1,517

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Stockholders' Equity

For the three and six months ended June 30, 2021

(in millions)


	Three months ended June 30, 2021
	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	$	—	$	1,270	$	(217)	$	(8)	$	1,046	$	35	$	1,081
Net (loss) income(a)	—		—		—		(111)		—		(111)		4		(107)

Distributions to noncontrolling interest holders	—		—		—		—		—		—		(17)		(17)

Share-based compensation	—		—		3		—		—		3		—		3



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



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


	Six months ended June 30, 2021
	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(a)	—		—		—		(205)		—		(205)		9		(196)

Distributions to noncontrolling interest holders	—		—		—		—		—		—		(31)		(31)

Share-based compensation	—		—		5		—		—		5		—		5



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



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

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

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

For the three and six months ended June 30, 2022 and 2021

(in millions)



	Three months ended June 30,				Six months ended June 30,
	2022		2021		2022		2021
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)	$	190	$	(107)	$	15	$	(196)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	50		54		99		106
Deferred income tax expense	62		—		29		—
Asset impairments	2		—		2		3
Net loss from commodity derivatives	100		265		662		478
Net payments on settled commodity derivatives	(241)		(82)		(422)		(121)
Net loss on early extinguishment of debt	—		—		—		2

Net gain on asset divestitures	(4)		—		(58)		(2)



Other non-cash charges to income, net	19		22		27		29
Changes in operating assets and liabilities, net	3		(25)		(13)		(25)
Net cash provided by operating activities	181		127		341		274

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(98)		(50)		(197)		(77)
Changes in accrued capital investments	6		8		9		13
Proceeds from asset divestitures	16		—		76		2
Acquisitions	—		—		(17)		—
Other	—		(1)		—		(1)
Net cash used in investing activities	(76)		(43)		(129)		(63)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from Revolving Credit Facility	—		—		—		16
Repayments of Revolving Credit Facility	—		—		—		(115)





Proceeds from Senior Notes	—		—		—		600

Debt issuance costs	—		(1)		—		(13)
Repayment of Second Lien Term Loan	—		—		—		(200)
Repayment of EHP Notes	—		—		—		(300)

Repurchases of common stock	(96)		(45)		(167)		(45)
Common stock dividends	(13)		—		(26)		—


Distributions paid to a noncontrolling interest holder	—		(17)		—		(31)


Net cash used in financing activities	(109)		(63)		(193)		(88)
(Decrease) Increase in cash	(4)		21		19		123
Cash—beginning of period	328		130		305		28
Cash—end of period	$	324	$	151	$	324	$	151

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

June 30, 2022

NOTE 1 BASIS OF PRESENTATION

We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We are committed to energy transition 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 permitting several carbon capture and storage projects in California and on August 3, 2022, we entered into a strategic partnership as discussed further in Note 15 Subsequent Events to develop certain projects. Separately, we are evaluating the feasibility of a carbon capture system to be located at our Elk Hills power plant (CalCapture). 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 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, 2021 (2021 Annual Report).

The carrying amounts of cash and on-balance sheet financial instruments, other than debt, approximate fair value. Refer to Note 6 Debt for the fair value of our debt.

NOTE 2 ACCOUNTING AND DISCLOSURE CHANGES

In February 2022, we amended our Revolving Credit Facility to replace the benchmark rate from the London Interbank Offered Rate to the secured overnight financing rate (SOFR). As a result of this amendment, we can elect to borrow at either an adjusted SOFR rate or an alternate base rate (ABR), subject to a 1% floor and 2% floor, respectively, plus an applicable margin. The ABR is equal to the highest of (i) the federal funds effective rate plus 0.50%, (ii) the administrative agent prime rate and (iii) the one-month SOFR rate plus 1%. The applicable margin is adjusted based on the borrowing base utilization percentage and will vary from (i) in the case of SOFR loans, 3% to 4% and (ii) in the case of ABR loans, 2% to 3%. The unused portion of the facility is subject to a commitment fee of 0.50% per annum. We also pay customary fees and expenses. Interest on ABR loans is payable quarterly in arrears. Interest on SOFR loans is payable at the end of each SOFR period, but not less than quarterly.

ASC Topic 848, Reference Rate Reform contains guidance for applying U.S. GAAP to contracts, hedging relationships and other transactions that are impacted by reference rate reform. Under this guidance, we elected to account for this debt amendment as a modification of the original instrument. The debt modification did not have a material impact to our condensed consolidated financial statements.

NOTE 3 SUPPLEMENTAL BALANCE SHEET INFORMATION

Other current assets — Other current assets includes the following:



	June 30,		December 31,
	2022		2021
	(in millions)
Amounts due from joint interest partners	$	43	$	47

Fair value of derivative contracts	27		6
Prepaid expenses	18		16
Greenhouse gas allowances	23		31
Margin deposits	5		12
Other	11		9
Other current assets	$	127	$	121

Other noncurrent assets - Other noncurrent assets includes the following:



	June 30,		December 31,
	2022		2021
	(in millions)
Operating lease right-of-use assets	$	39	$	43
Deferred financing costs - Revolving Credit Facility	8		11
Emission reduction credits	11		11
Prepaid power plant maintenance	25		21
Fair value of derivative contracts	24		1
Deposits and other	18		11
Other noncurrent assets	$	125	$	98

Accrued liabilities — Accrued liabilities includes the following:



	June 30,		December 31,
	2022		2021
	(in millions)
Accrued employee-related costs	$	58	$	61
Accrued taxes other than on income	33		30
Asset retirement obligations	68		51
Accrued interest	19		19
Lease liability	10		11

Premiums due on derivative contracts	86		57
Liability for settlement payments on derivative contracts	67		25
Amounts due under production-sharing contracts	35		14
Other	26		29
Accrued liabilities	$	402	$	297

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



	June 30,		December 31,
	2022		2021
	(in millions)
Compensation-related liabilities	$	33	$	38
Postretirement and pension benefit plans	56		59
Lease liability	34		37

Premiums due on derivative contracts	31		5
Other	6		6
Other long-term liabilities	$	160	$	145

NOTE 4 SUPPLEMENTAL CASH FLOW INFORMATION

We paid $20 million of U.S. federal income tax payments during the three and six months ended June 30, 2022. We did not make U.S. federal and state income tax payments during the three and six months ended June 30, 2021.

Interest paid, net of capitalized amounts was insignificant for the three months ended June 30, 2022 and $2 million for the three months ended June 30, 2021. Interest paid, net of capitalized amounts was $22 million and $4 million for the six months ended June 30, 2022 and 2021, respectively.

Non-cash investing activities in the three and six months ended June 30, 2022 included $1 million of additional earn-out consideration related to our Ventura basin divestiture.

Non-cash financing activities in the three and six months ended June 30, 2022 included $1 million of dividends accrued for stock-based compensation awards. No dividends were accrued for the three or six months ended June 30, 2021.

NOTE 5 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 include produced oil and NGLs in storage, which are valued at the lower of cost or net realizable value. Inventories, by category, are as follows:



	June 30,		December 31,
	2022		2021
	(in millions)
Materials and supplies	$	53	$	54
Finished goods	4		6
Inventories	$	57	$	60

NOTE 6 DEBT

As of June 30, 2022 and December 31, 2021, our long-term debt consisted of the following:



	June 30,		December 31,
	2022		2021		Interest Rate	Maturity
	(in millions)

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

Senior Notes	600		600		7.125%	February 1, 2026
Principal amount	$	600	$	600
Unamortized debt issuance costs	(9)		(11)
Long-term debt, net	$	591	$	589

Revolving Credit Facility

On October 27, 2020, we entered into a Credit Agreement with Citibank, N.A., as administrative agent, and certain other lenders. This credit agreement currently consists of a senior revolving loan facility (Revolving Credit Facility) with an aggregate commitment of $552 million, which we are permitted to increase if we obtain additional commitments from new or existing lenders. This amount includes $60 million of additional commitments from new lenders that we obtained in February 2022. Our Revolving Credit Facility also includes a sub-limit of $200 million for the issuance of letters of credit. Letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

The borrowing base is redetermined semi-annually and was reaffirmed at $1.2 billion on April 29, 2022. 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 April 29, 2022, we amended our Revolving Credit Facility to, among other things, modify the minimum hedge requirement and the restricted payment and investment covenants contained in the Revolving Credit Facility.

As a result of this amendment, the rolling hedge requirement as described in Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2021 Annual Report has been modified. As amended, our Revolving Credit Facility requires us to maintain hedges on a minimum amount of crude oil production (determined on (i) the date of delivery of annual and quarterly financial statements and (ii) the date of delivery of a reserve report delivered in connection with an interim borrowing base redetermination) of no less than (i) in the event that our Consolidated Total Net Leverage Ratio (as defined in the Credit Agreement) is greater than 2:1 as of the end of the most recent fiscal quarter test period, 50% of our reasonably anticipated oil production from our proved developed producing reserves for each quarter during the period ending the earlier of (1) the maturity date of the Revolving Credit Facility and (2) 12 months after the delivery of the compliance certificate for the relevant test period and (ii) in the event that our Consolidated Total Net Leverage Ratio is less than or equal to 2:1 but greater than 1:1 as of the end of the most recent fiscal quarter test period, 33% of our reasonably anticipated oil production from our proved developed producing reserves for each quarter during the period ending the earlier of (1) the maturity date of the Revolving Credit Facility and (2) 12 months after the delivery of the compliance certificate for the relevant test period. The foregoing minimum hedge requirements do not apply to the extent that our Consolidated Total Net Leverage Ratio is less than or equal to 1:1 as of the last day of the most recently ended fiscal quarter test period.

Furthermore, the restricted payment and investments covenants were modified to permit unlimited investments and/or restricted payments so long as (i) no Default, Event of Default or Borrowing Base Deficiency shall have occurred and be continuing under the Revolving Credit Facility at the time of such investment or restricted payment, (ii) the undrawn availability under the Revolving Credit Facility at such time is not less than 30.0% of the total commitment and (iii) the Consolidated Total Net Leverage Ratio is less than or equal to 1.5:1.

As of June 30, 2022, our availability under our Revolving Credit Facility was as follows:



	June 30,
	2022
	(in millions)
Borrowing capacity	$	552
Outstanding letters of credit	(136)
Availability	$	416

At June 30, 2022, we were in compliance with all financial and other debt covenants under our Revolving Credit Facility and Senior Notes.

Fair Value

The estimated fair value of our fixed-rate debt at June 30, 2022 and December 31, 2021 was approximately $581 million and $623 million, respectively. We estimate fair value based on prices known from market transactions (Level 1).

NOTE 7 DIVESTITURES AND ACQUISITIONS

Divestitures

Ventura Basin Transactions

During the second quarter of 2021, we entered into transactions to sell our Ventura basin assets. The transactions contemplate multiple closings that are subject to customary closing conditions.

During the three and six months ended June 30, 2022, we recorded a gain of $4 million and $10 million, respectively, related to the sale of certain Ventura basin assets. The amount recognized in the three months ended June 30, 2022 of $4 million related to additional earn-out consideration on closings that occurred in the second half of 2021 and the first half of 2022. In addition, we also received $2 million to secure performance of abandonment obligations which we expect to reimburse to the buyer once the abandonment obligations are met. As a result, we recorded a liability of $2 million included as accrued liabilities on our condensed consolidated balance sheet as of June 30, 2022, and we did not recognize gain on asset divestitures for this portion of the transaction. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions in our 2021 Annual Report for additional information on the Ventura basin transactions.

We expect to divest of our remaining assets in the Ventura basin during the second half of 2022, pending final approval from the State Lands Commission. These remaining assets, consisting of property, plant and equipment and the associated asset retirement obligations, are classified as held for sale on our condensed consolidated balance sheet as of June 30, 2022.

Lost Hills Transaction

On February 1, 2022, we sold our 50% non-operated working interest in certain horizons within our Lost Hills field, located in the San Joaquin basin, recognizing a gain of $49 million. We retained an option to capture, transport and store 100% of the CO2 from steam generators across the Lost Hills field for future carbon management projects. We also retained 100% of the deep rights and related seismic data.

CRC Plaza

In June 2022, we sold our commercial office building located in Bakersfield, California for net proceeds of $13 million, recognizing no gain or loss on sale. In May 2022, we recorded a $2 million impairment charge to write down the carrying value of the building to its fair value, which was determined based on a market approach (using Level 3 inputs in the fair value hierarchy). As part of the sale, we entered into an operating lease for a portion of the building with a term of 18 months. Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Property, Plant and Equipment in our 2021 Annual Report for information regarding an impairment charge to CRC Plaza recorded in 2021.

Other

During the six months ended June 30, 2022, we sold non-core assets recognizing a $1 million loss. During the six months ended June 30, 2021, we sold non-core assets recognizing a $2 million gain.

Acquisitions

During the six months ended June 30, 2022, we acquired properties and land easements for carbon management activities for approximately $17 million. There were no acquisitions for the three months ended June 30, 2022.

NOTE 8 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

Litigation and Claims

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 for these items at June 30, 2022 and December 31, 2021 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 was 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 are challenging the order from BSEE.

Commitment

During the second quarter of 2022, we entered into an agreement to extend our $12 million commitment to invest capital at one of our oil and natural gas properties from May 2022 to December 31, 2022, with an optional six-month extension. The agreement may relieve us from our remaining obligation upon acceptance of certain land use requirements which may occur on or before December 31, 2022, with similar extension options.

NOTE 9 DERIVATIVES

We maintain a commodity hedging program primarily focused on crude oil to help protect our cash flows, margins and capital program from the volatility of commodity prices. We did not have any derivative instruments designated as accounting hedges as of and for the three and six months ended June 30, 2022 and 2021. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging requirements and program goals.

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. See Note 6 Debt for more information on an amendment to our Revolving Credit Facility and our hedging requirements.

Summary of open derivative contracts — We held the following Brent-based crude oil contracts as of June 30, 2022:


	Q3 2022		Q4 2022		Q1 2023		Q2 2023		2H 2023		2024
Sold Calls
Barrels per day	34,380		25,167		18,322		17,837		11,555		—
Weighted-average price per barrel	$	60.76	$	57.82	$	57.28	$	60.00	$	57.06	$	—

Swaps
Barrels per day	10,476		17,263		14,620		14,475		19,395		1,492
Weighted-average price per barrel	$	53.97	$	58.79	$	67.36	$	66.36	$	68.05	$	79.06

Net Purchased Puts(a)
Barrels per day	34,380		25,167		18,322		17,837		11,555		1,724
Weighted-average price per barrel	$	65.02	$	64.47	$	76.25	$	76.25	$	76.25	$	75.00

Sold Puts
Barrels per day	4,000		1,348		—		—		—		—
Weighted-average price per barrel	$	32.00	$	32.00	$	—	$	—	$	—	$	—

(a)Purchased puts and sold puts with the same strike price have been presented on a net basis.

We held the following SoCal Border-based natural gas contracts as of June 30, 2022:


	Q3 2022		Q4 2022		Q1 2023		Q2 2023		2H 2023		2024
Swaps
MMBTU per day	25,000		25,000		—		—		—		—
Weighted-average price per MMBTU	$	7.78	$	7.74	$	—	$	—	$	—	$	—

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.

•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.

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

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

We use combinations of these positions to increase the efficacy of our hedging program and, subject to certain conditions, meet the requirements of our Revolving Credit Facility. The majority of our derivative positions for the remainder of 2022 and 2023 were entered into subsequent to our emergence from bankruptcy to comply with the hedging requirements of our Revolving Credit Facility that were applicable at the time.

Fair value of derivatives — The following tables present the fair values on a recurring basis (at gross and net) of our outstanding commodity derivatives as of June 30, 2022 and December 31, 2021:


June 30, 2022
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	(in millions)
Other current assets	$	49	$	(22)	$	27
Other noncurrent assets	39		(15)		24

Liabilities
Current - Fair value of derivative contracts	(536)		22		(514)
Noncurrent - Fair value of derivative contracts	(148)		15		(133)
	$	(596)	$	—	$	(596)


December 31, 2021
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	(in millions)
Other current assets	$	33	$	(27)	$	6
Other noncurrent assets	12		(11)		1

Liabilities
Current - Fair value of derivative contracts	(297)		27		(270)
Noncurrent - Fair value of derivative contracts	(143)		11		(132)
	$	(395)	$	—	$	(395)

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 loss from commodity derivatives on our condensed consolidated statements of operations for the three and six months ended June 30, 2022 and 2021. 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 10 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) were calculated using the treasury stock method for the three and six months ended June 30, 2022 and 2021. Our restricted stock unit (RSU) and performance stock unit (PSU) awards are not considered participating securities since the dividend rights on unvested shares are forfeitable.

For basic EPS, the weighted-average number of common shares outstanding excludes shares underlying our equity-settled awards and warrants. For diluted EPS, the basic shares outstanding are adjusted by adding potential common shares, if dilutive.

The following table presents the calculation of basic and diluted EPS, for the three and six months ended June 30, 2022 and 2021:



	Three months ended June 30,				Six months ended June 30,
	2022		2021		2022		2021
	(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS
Net income (loss)	$	190	$	(107)	$	15	$	(196)
Less: net income attributable to noncontrolling interests	—		(4)		—		(9)
Net income (loss) attributable to common stock	$	190	$	(111)	$	15	$	(205)



Denominator for Basic EPS
Weighted-average shares	76.7		83.1		77.6		83.2

Potential Common Shares, if dilutive:
Warrants	0.7		—		0.7		—
Restricted Stock Units	0.7		—		0.7		—
Performance Stock Units	0.7		—		0.6		—

Denominator for Diluted EPS
Weighted-average shares	78.8		83.1		79.6		83.2

EPS
Basic	$	2.48	$	(1.34)	$	0.19	$	(2.46)
Diluted	$	2.41	$	(1.34)	$	0.19	$	(2.46)

The following table presents potentially dilutive weighted-average common shares which were excluded from the denominator for diluted EPS in periods of losses:



	Three months ended June 30,		Six months ended June 30,
	2022	2021	2022	2021
	(in millions)
Shares issuable upon exercise of warrants	—	4.4	—	4.4

Shares issuable upon settlement of RSUs	—	1.1	—	0.8
Shares issuable upon settlement of PSUs	—	0.9	—	0.7

Total antidilutive shares	—	6.4	—	5.9

NOTE 11 PENSION AND POSTRETIREMENT BENEFIT PLANS

The following table sets forth the components of the net periodic benefit costs for our defined benefit pension and postretirement benefit plans for the three and six months ended June 30, 2022 and 2021:



	Three months ended June 30,				Three months ended June 30,
	2022				2021
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
	(in millions)				(in millions)
Service cost - benefits earned during the period	$	1	$	—	$	1	$	1
Interest cost on projected benefit obligation	—		1		—		1
Expected return on plan assets	—		—		(1)		—


Amortization of prior service cost credit	—		(2)		—		—
Net periodic benefit costs	$	1	$	(1)	$	—	$	2



	Six months ended June 30,				Six months ended June 30,
	2022				2021
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
	(in millions)				(in millions)
Service cost - benefits earned during the period	$	1	$	1	$	1	$	2
Interest cost on projected benefit obligation	—		1		—		2
Expected return on plan assets	—		—		(1)		—


Amortization of prior service cost credit	—		(3)		—		—
Net periodic benefit costs	$	1	$	(1)	$	—	$	4

We did not make any significant contributions for the three months ended June 30, 2022 and contributed approximately $1 million to our defined benefit plans during the six months ended June 30, 2022. We contributed approximately $1 million to our defined benefit plans during the three and six months ended June 30, 2021. We expect to satisfy minimum funding requirements with contributions of approximately $1 million to our defined benefit pension plans during the remainder of 2022.

NOTE 12 INCOME TAXES

The difference between the U.S. federal statutory tax rate of 21% and our effective tax rate of 29% for the three months ended June 30, 2022 primarily relates to state taxes. The difference between the U.S. federal statutory tax rate of 21% and our effective tax rate of 77% for the six months ended June 30, 2022 primarily relates to state taxes and recording a valuation allowance for a capital loss realized on the Lost Hills divestiture, the deductibility of which is limited to future capital gains. The difference between the U.S. federal statutory tax rate of 21% and our effective tax rate of zero for the three and six months ended June 30, 2021, primarily relates to state taxes and changes to maintain a full valuation allowance against our net deferred tax assets given our anticipated future earnings trends at that time.

Realization of our deferred tax assets is subjective and remains dependent on a number of factors including our ability to generate sufficient taxable income, including capital gains, in future periods.

NOTE 13 STOCKHOLDERS' EQUITY

Share Repurchase Program

Our Board of Directors authorized a Share Repurchase Program to acquire up to $650 million of our common stock through June 30, 2023. 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.

For the three months ended June 30, 2022, we repurchased 2,255,445 shares of our common stock at an average price of $42.57 per share for $96 million. For the six months ended June 30, 2022, we repurchased 3,923,901 shares of our common stock at an average price of $42.55 per share for $167 million. For the three and six months ended June 30, 2021, we repurchased 1,440,203 shares of our common stock, at an average price of $31.56 per share for $45 million.

As of June 30, 2022, we have repurchased an aggregate 8,013,889 shares of our common stock, at an average price of $39.26 per share for $315 million, since inception of the Share Repurchase Program in May 2021. Shares repurchased were held as treasury stock as of June 30, 2022.

Dividends

On February 23, 2022, our Board of Directors declared a quarterly cash dividend of $0.17 per share of common stock. The dividend was payable to shareholders of record at the close of business on March 7, 2022 and was paid on March 16, 2022. On May 4, 2022, our Board of Directors declared a quarterly cash dividend of $0.17 per share of common stock. The dividend was payable to shareholders of record at the close of business on June 1, 2022 and was paid on June 16, 2022.

Future cash dividends, and the establishment of record and payment dates, are subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. See Note 15 Subsequent Events for information on future cash dividends.

Warrants

We reserved an aggregate 4,384,182 shares of our common stock for warrants which are exercisable at $36 per share through October 26, 2024. The Warrant Agreement contains customary anti-dilution adjustments in the event of any stock split, reverse stock split, stock dividend and certain 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 10 Equity in our 2021 Annual Report for a description of our warrants and Note 14 Chapter 11 Proceedings for more information on the issuance of these warrants pursuant to our joint plan of reorganization.

During the three and six months ended June 30, 2022, we issued an insignificant number of shares of our common stock in exchange for warrants. As of June 30, 2022, we had outstanding warrants exercisable into 4,295,434 shares of our common stock (subject to adjustments pursuant to the terms of the warrants).

Noncontrolling Interests

Our development joint venture with Benefit Street Partners (BSP JV) contemplated that BSP contributed funds for the development of our oil and natural gas properties in exchange for preferred interests in the BSP JV. In September 2021, BSP's preferred interest was automatically redeemed in full under the terms of the joint venture agreement. Prior to redemption, BSP's preferred interest was reported in equity on our condensed consolidated balance sheets and BSP’s share of net income (loss) was reported in net income attributable to noncontrolling interests in our condensed consolidated statements of operations.

NOTE 14 REVENUE RECOGNITION

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

The following table provides disaggregated revenue for sales of produced oil, natural gas and NGLs to customers:



	Three months ended June 30,				Six months ended June 30,
	2022		2021			2022		2021
	(in millions)
Oil	$	547	$	380		$	1,033	$	711
Natural gas	94		45			174		92
NGLs	77		53			139		107
Oil, natural gas and NGL sales	$	718	$	478		$	1,346	$	910

NOTE 15 SUBSEQUENT EVENTS

Carbon TerraVault Joint Venture

In August 2022, we entered into a Joint Venture and Investment Agreement, and a series of other agreements, with BGTF Sierra Aggregator LLC (Brookfield) to form a joint venture for the development of a carbon management business in California (Carbon TerraVault JV). The joint venture, through a series of wholly owned subsidiaries, will build, install, operate and maintain CO2 capture equipment, transportation assets and storage facilities.

We acquired a 51% interest in the Carbon TerraVault JV through the contribution of rights to inject CO2 into the 26R reservoir in our Elk Hills Field for permanent CO2 storage. Brookfield acquired a 49% interest in the Carbon TerraVault JV in exchange for an initial investment of $137 million, payable in three equal installments upon completion of certain milestones. The first installment of $46 million was funded on August 3, 2022. Brookfield has committed an initial $500 million to invest in CCS projects that are jointly approved through the JV, inclusive of the initial investment of $137 million.

Dividends

On August 3, 2022, 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 September 1, 2022 and is expected to be paid on September 16, 2022.

Employee Stock Purchase Plan

In May 2022, our shareholders approved a new California Resources Corporation Employee Stock Purchase Plan (ESPP), which took effect in July 2022. The ESPP will provide our employees with the ability to purchase shares of our common stock at a price equal to 85% of the closing price of a share of our common stock as of the first or last day of each fiscal quarter, whichever amount is less. The maximum number of shares of our common stock which may be issued pursuant to the ESPP is subject to certain annual limits and has a cumulative limit of 1,250,000 shares.

Share Repurchase Program

In July 2022, we repurchased 1,122,947 shares of our common stock at an average price of $40.00 per share for $45 million. As of July 31, 2022, we have repurchased an aggregate 9,136,836 shares of our common stock, at an average price of $39.34 per share for $360 million, since the inception of the Share Repurchase Program in May 2021.

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 make value-based capital investments. Further, we are committed to energy transition 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 storage projects in California. Currently, we have applied for permits for two initial permanent CCS projects at the Elk Hills Field. In May 2022, we applied for permits for an additional 80 MMT of carbon storage, which once approved, will increase our total potential permitted storage to 120 MMT. We are targeting filing additional carbon storage permits before the end of 2022, which, once approved, would increase our total permitted storage to 200 MMT to be utilized in carbon capture and storage projects. Separately, we are evaluating the feasibility of a carbon capture system to be located at our Elk Hills power plant (CalCapture). We will be conducting a new front-end engineering design (FEED) study to explore the application of proprietary post-combustion capture and compression of up to 95% of the CO2 emissions from the Elk Hills power plant. We are also pursuing multiple solar projects for supplying the grid (front-of-the-meter solar) and powering our operations (behind-the-meter solar).

While all of these projects are in early stages, we expect that the size and scope of our projects providing these and similar services and capital spent on such projects will continue to grow given our strategy of expansion into these services. For more information about the risks involved in our carbon capture projects, see Part I, Item 1A – Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2021 (2021 Annual Report).

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 consolidated subsidiaries.

Joint Ventures

Carbon TerraVault Joint Venture

Dividends

In 2021, our Board of Directors approved a cash dividend policy which anticipates a total annual dividend of $0.68 per share of common stock, payable in quarterly increments of $0.17 per share of common stock. On August 3, 2022, 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 September 1, 2022 and is expected to be paid on September 16, 2022. 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 aggregate payment for this quarterly dividend is approximately $13 million.

Share Repurchase Program

Our Board of Directors authorized a Share Repurchase Program to acquire up to $650 million of our common stock through June 30, 2023. 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 and contractual limitations in our debt agreements. 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 July 31, 2022, we have repurchased an aggregate 9,136,836 shares of our common stock, at an average price of $39.34 per share for $360 million, since the inception of the Share Repurchase Program in May 2021. Shares repurchased are held as treasury stock. See Part I, Item 1 – Financial Statements, Note 13 Equity for more information on our share repurchase activity during the three and six months ended June 30, 2022.

Divestitures and Acquisitions

See Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions for information on our transactions during the three and six months ended June 30, 2022 and 2021.

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 increased in the first half of 2022 with Russia's invasion of Ukraine and following boycotts of Russian oil and sanctions imposed on Russia by the United States and other countries, increasing demand from the remaining world producers of oil. Global oil prices were also positively impacted as demand outpaced supply as COVID-19 restrictions eased. In the United States, natural gas prices were influenced by increased domestic demand, global demand for natural gas in the form of liquified natural gas exports as a result of the Russia-Ukraine conflict and concerns over low inventories. Natural gas prices also rose during the first half of 2022 due to a colder-than-normal winter that increased demand while supplies remained steady. Commodity prices have recently declined slightly from the high experienced in the second quarter and the demand for commodities could decline further due to, among other things, a prolonged high inflationary environment or a recession or a widespread resurgence of the COVID-19 outbreak. Although the forward strip prices for commodities remains high relative to commodity prices in recent years for the next twelve months and beyond, the current commodity price environment remains uncertain. The extent to which commodity prices and our operating and financial results of future periods will be impacted by the ongoing conflict in Ukraine, increasing inflation, government efforts to reduce inflation, any recession, the COVID-19 pandemic and the actions of foreign oil and gas producers will depend largely on future developments, which are highly uncertain and cannot be accurately predicted.

The following table presents the average daily benchmark prices for oil and natural gas during the periods presented:


	Three months ended				Six months ended
	June 30, 2022		March 31, 2022		June 30, 2022		June 30, 2021
Brent oil ($/Bbl)	$	111.79	$	97.38	$	104.59	$	65.06
WTI oil ($/Bbl)	$	108.41	$	94.29	$	101.35	$	61.96
NYMEX Henry Hub ($/MMBtu) Average Daily Price	$	6.62	$	4.19	$	5.40	$	2.74
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	$	7.17	$	4.95	$	6.06	$	2.76

Supply Chain and Cost Inflation

Operating and capital costs in the oil and natural gas industry are heavily influenced by commodity price environments which are cyclical in nature. Typically, suppliers will negotiate increases for drilling and completion, oilfield services, equipment and materials as prices for energy-related commodities and raw materials (such as steel, metals and chemicals) increase. Recent worldwide and U.S. supply chain issues, together with rising commodity prices and tight labor markets in the U.S., have created cost inflation during 2022 which may continue in future periods. We have taken measures to limit the effects of the inflationary market by entering into contracts for materials and services with terms of one to three years. We have also taken steps to build our on-hand supply stock for items frequently used in our operations to address possible supply chain disruptions. Despite these efforts, we have experienced significant increased costs thus far in 2022 and we anticipate additional increases in the cost of goods and services and wages in our operations during the remainder of 2022. These increases will factor into our operating and capital costs for the second half of 2022 and could also negatively impact our results of operations and cash flows in 2023 and beyond.

Regulatory Update

CalGEM is California's primary regulator of the oil and natural gas industry on private and state lands, with additional oversight from the State Lands Commission’s administration of state surface and mineral interests. CalGEM currently requires an operator to identify the manner in which the California Environmental Quality Act (CEQA) has been satisfied prior to issuing various state permits, typically through either an environmental review or an exemption by a state or local agency. In Kern County, this requirement has typically been satisfied by complying with the local oil and gas ordinance which was supported by an Environmental Impact Report (EIR) certified by the Kern County Board of Supervisors in 2015.

A group of petitioners has challenged the EIR and on February 25, 2020, a California Appellate Court issued a ruling that required Kern County to decertify the EIR and set aside the amended Zoning Ordinance. In response, Kern County prepared, circulated and certified a supplementary recirculated EIR (Supplemental EIR) to address the ruling from the Court and, in April 2021, resumed issuing local permits relying on the Supplemental EIR. However, on May 26, 2022, a hearing was held in Kern County and the Court ruled that Kern County’s local permitting system must cease until the trial court has verified that the noted deficiencies have been remedied and that the remedies satisfy the concerns raised by the Appellate Court. The next hearing of the trial court is scheduled for September 28, 2022.

If the EIR is not reinstated or adequately modified following resolution of the litigation described above, obtaining drilling permits for our operations in areas where we do not have field or project specific CEQA coverage could be delayed or become more costly as a result of compliance with CEQA. We have CEQA coverage at Elk Hills and Wilmington fields, which are two of our most significant assets. We believe that we currently have a sufficient inventory of drilling permits for our anticipated operations through 2022.

Production

The following table sets forth our average net production of oil, NGLs and natural gas per day in each of the California oil and natural gas basins in which we operated for the periods presented. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions in our 2021 Annual Report for information regarding the divestiture of our Ventura basin operations and Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions above for information regarding the divestiture of our 50% non-operated working interest in certain horizons within our Lost Hills field, located in the San Joaquin basin.


	Three months ended		Six months ended
	June 30, 2022	March 31, 2022		June 30, 2022	June 30, 2021
Oil (MBbl/d)
San Joaquin Basin	38	38		38	38
Los Angeles Basin	16	18		17	20
Ventura Basin	—	—		—	2

Total	54	56		55	60
NGLs (MBbl/d)
San Joaquin Basin	12	9		11	12

Ventura Basin	—			—	1

Total	12	9		11	13
Natural gas (MMcf/d)
San Joaquin Basin	132	121		127	135
Los Angeles Basin	1	1		1	1
Ventura Basin	—	—		—	5
Sacramento Basin	18	19		18	20
Total	151	141		146	161

Total Net Production (MBoe/d)	91	88		90	100

Total daily net production for the three months ended June 30, 2022, compared to the three months ended March 31, 2022 increased by approximately 3 MBoe/d, or 3%. This increase includes approximately 5 MBoe/d resulting from the return of production at one of our cryogenic gas processing facilities, which had planned maintenance during the first quarter of 2022. These increases were partially offset by decreases resulting from natural decline and the divestiture of our remaining 50% working interest in certain zones in the Lost Hills field in February 2022. Our production-sharing contracts (PSCs), which are described below, negatively impacted our net oil production in the three months ended June 30, 2022 by approximately 1 MBoe/d, compared to the three months ended March 31, 2022.

Total daily net production for the six months ended June 30, 2022, compared to the same period in 2021, decreased by approximately 10 MBoe/d, or 10%. The decrease in production includes the divestiture of our remaining 50% working interest in certain zones in the Lost Hills field in February 2022 and the divestiture of our Ventura basin operations beginning in the fourth quarter of 2021, which reduced our total net production by approximately 5 MBoe/d for the six months ended June 30, 2022 compared to the prior year period. The decrease also included planned maintenance at one of our cryogenic gas processing facilities in the first quarter of 2022 as well as natural decline. These decreases were partially offset by improved operational results from our developmental 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 PSCs, which are described below, negatively impacted our net oil production in the six months ended June 30, 2022 by approximately 1 MBoe/d, compared to the same period in 2021.

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, operating and abandonment costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital, operating and abandonment 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 14% and 15% of our net production for the three and six months ended June 30, 2022, respectively.

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. Operating costs, excluding effects of PSC-type contracts is a non-GAAP measure which adjusts for excess costs attributable to PSC-type contracts for the periods presented in the tables below:


	Three months ended
	June 30, 2022				March 31, 2022
	(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs	$	190	$	22.92	$	182	$	22.87
Excess costs attributable to PSC-type contracts	(21)		$	(2.58)	(18)		$	(2.30)
Operating costs, excluding effects of PSC-type contracts	$	169	$	20.34	$	164	$	20.57


	Six months ended
	June 30, 2022				June 30, 2021
	(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs	$	372	$	22.90	$	333	$	18.40
Excess costs attributable to PSC-type contracts	(40)		$	(2.45)	(30)		$	(1.66)
Operating costs, excluding effects of PSC-type contracts	$	332	$	20.45	$	303	$	16.74

The following table reconciles our average net production to our average gross production (which includes production from the fields we operate and our share of production for fields operated by others.) for the periods presented:


	Three months ended		Six months ended
	June 30, 2022	March 31, 2022	June 30, 2022	June 30, 2021
	(MBoe/d)
Total Net Production	91	88	90	100
Partners' share under PSC contracts	8	7	7	6
Other working interest and royalty holders' share	8	9	8	11
Other	1	1	1	1
Total Gross Production	108	105	106	118

Prices and Realizations

The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX indexes for our products for the periods presented:


	Three months ended
	June 30, 2022			March 31, 2022
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	111.79		$	97.38

Realized price without derivative settlements	$	112.32	100%	$	96.13	99%
Effects of derivative settlements	(49.15)			(35.83)
Realized price with derivative settlements	$	63.17	57%	$	60.30	62%

WTI	$	108.41		$	94.29

Realized price without derivative settlements	$	112.32	104%	$	96.13	102%
Realized price with derivative settlements	$	63.17	58%	$	60.30	64%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	68.29	61%	$	78.63	81%
Realized price (% of WTI)	$	68.29	63%	$	78.63	83%

Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Daily Price	$	6.62		$	4.19

Realized price without derivative settlements ($/Mcf)	$	6.85	103%	$	6.28	150%
Effects of derivative settlements	(0.13)			—
Realized price with derivative settlements ($/Mcf)	$	6.72	102%	$	6.28	150%

NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	7.17		$	4.95

Realized price without derivative settlements ($/Mcf)	$	6.85	96%	$	6.28	127%
Effects of derivative settlements	(0.13)			—
Realized price with derivative settlements ($/Mcf)	$	6.72	94%	$	6.28	127%


	Six months ended
	June 30, 2022			June 30, 2021
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	104.59		$	65.06

Realized price without derivative settlements	$	104.07	100%	$	64.89	100%
Effects of derivative settlements	(42.36)			(10.98)
Realized price with derivative settlements	$	61.71	59%	$	53.91	83%

WTI	$	101.35		$	61.96

Realized price without derivative settlements	$	104.07	103%	$	64.89	105%
Realized price with derivative settlements	$	61.71	61%	$	53.91	87%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	72.57	69%	$	46.75	72%
Realized price (% of WTI)	$	72.57	72%	$	46.75	75%

Natural gas
NYMEX Henry Hub ($/MMBtu) Average Daily Price	$	5.40		$	2.74

Realized price without derivative settlements ($/Mcf)	$	6.58	122%	$	3.17	116%
Effects of derivative settlements	(0.07)			(0.03)
Realized price with derivative settlements ($/Mcf)	$	6.51	121%	$	3.14	115%

NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	$	6.06		$	2.76

Realized price without derivative settlements ($/Mcf)	$	6.58	109%	$	3.17	115%
Effects of derivative settlements	(0.07)			(0.03)
Realized price with derivative settlements ($/Mcf)	$	6.51	107%	$	3.14	114%

Oil — Brent prices increased for the three months ended June 30, 2022 compared to the three months ended March 31, 2022 as a demand continued to outpace supply. Prices also increased for the six months ended June 30, 2022 compared to the same prior-year period as the effects of the COVID-19 pandemic have subsided leaving crude oil production and product inventories at low levels. As demand has rebounded, producers have generally maintained capital discipline, OPEC+ members have failed to produce at stepped-up quotas, and the conflict between Russia and Ukraine has created a disconnect between buyers and sellers of Russian produced crude oil.

NGLs — NGL prices for the three months ended June 30, 2022 decreased compared to the three months ended March 31, 2022 as a result of seasonal winter premiums coming out of the market and pricing weakness caused by higher production. NGL prices for the six months ended June 30, 2022 increased compared to the six months ended June 30, 2021 as the NGL markets benefited from higher values in the market as a whole.

Natural Gas — Our realized price for natural gas increased for the three and six months ended June 30, 2022 as compared to the three months ended March 31, 2022 and six months ended June 30, 2021 as a result of increased demand domestically and on the export front in terms of liquefied natural gas exports and lower-than-average natural gas inventories.

Statements of Operations Analysis

Results of Oil and Gas Operations

In November 2020, the SEC amended Regulation S-K to, among other things, provide companies with the option to discuss material changes to results of operations between the current and immediately preceding quarter. We have elected to discuss our results of operations on a sequential-quarter basis. We believe this approach provides more meaningful and useful information to measure our performance from the immediately preceding quarter. In accordance with this final rule, we are not required to include a comparison of the current quarter and the same prior-year quarter.

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 months ended June 30, 2022 and March 31, 2022 and the six months ended June 30, 2022 and 2021. Energy operating costs consist of purchases of natural gas used to generate electricity, purchased electricity and internal costs to generate electricity used in our operations. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. However, non-energy operating costs include the costs of purchasing natural gas from third parties that is used to generate steam for our steamfloods.


	Three months ended				Six months ended
	June 30, 2022		March 31, 2022			June 30, 2022		June 30, 2021
	($ per Boe)
Energy operating costs	$	6.88	$	6.68		$	6.78	$	4.70
Gas processing costs	$	0.54	$	0.56		$	0.55	$	0.60
Non-energy operating costs	$	15.50	$	15.63		$	15.57	$	13.10
Operating costs	$	22.92	$	22.87		$	22.90	$	18.40


Field general and administrative expenses(a)	$	0.84	$	1.01		$	0.92	$	0.83
Field depreciation, depletion and amortization(b)	$	5.43	$	5.15		$	5.29	$	5.25
Field taxes other than on income	$	3.62	$	2.76		$	3.20	$	3.21

a.Excludes unallocated general and administrative expenses.

b.Excludes depreciation, depletion and amortization related to our corporate assets, carbon management assets and our Elk Hills power plant.

Operating costs for the three months ended June 30, 2022 were slightly higher than the three months ended March 31, 2021 on both a total and per Boe basis as a result of higher natural gas prices and increased compensation-related expenses. Operating costs in the six months ended June 30, 2022 were higher than the same period in 2021 primarily as a result of higher natural gas and electricity prices. Lower production volumes in 2022 also contributed to the increase on a per Boe basis. We expect operating costs related to repair and maintenance activities to increase during the second half of 2022 as inflationary pressures increase costs for services, labor and supplies.

Total field taxes other than on income for the three months ended June 30, 2022 were higher than the three months ended March 31, 2022 primarily related to increases in production taxes. Total field taxes other than on income were lower in the six months ended June 30, 2022 compared to the same period in 2021, but higher on a per Boe basis due to lower production volumes in 2022. The decrease in total field taxes was due to lower ad valorem taxes, partially offset by increased production taxes and higher greenhouse gas taxes due to emission levels as we increased activity and market prices.

Consolidated Results of Operations

Three months ended June 30, 2022 compared to March 31, 2022

The following table presents our operating revenues for the three months ended June 30, 2022 and March 31, 2022:


	Three months ended
	June 30, 2022		March 31, 2022
	(in millions)
Oil, natural gas and NGL sales	$	718	$	628
Net loss from commodity derivatives	(100)		(562)
Sales of purchased natural gas	75		32
Electricity sales	49		34
Other revenue	5		21
Total operating revenues	$	747	$	153

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $718 million for the three months ended June 30, 2022, which is an increase of $90 million compared to $628 million for the three months ended March 31, 2022. This increase was primarily due to higher realized prices and higher NGL production after we resumed operation at one of our cryogenic gas processing facilities following planned maintenance in the first quarter of 2022. These increases were partially offset by lower oil production as a result of asset divestitures and natural decline.


	Oil		NGLs		Natural Gas		Total
	(in millions)
Three months ended March 31, 2022	$	486	$	62	$	80	$	628
Changes in realized prices	82		(8)		6		80
Changes in production	(21)		23		8		10
Three months ended June 30, 2022	$	547	$	77	$	94	$	718

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

The effect of cash settlements on our commodity derivative contracts is not included in the table above. Payments on commodity derivatives were $241 million for the three months ended June 30, 2022 compared to payments of $181 million for the three months ended March 31, 2022. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $30 million, or 7% compared to the three months ended March 31, 2022.

Net loss from commodity derivatives — Net loss from commodity derivatives was $100 million for the three months ended June 30, 2022 compared to a net loss of $562 million for the three months ended March 31, 2022. The decrease in the net loss primarily resulted from 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 as shown in the table below:


	Three months ended
	June 30, 2022		March 31, 2022
	(in millions)
Non-cash commodity derivative gain (loss)	$	141	$	(381)


Net cash payments on settled commodity derivatives	(241)		(181)

Net loss from commodity derivatives	$	(100)	$	(562)

Sales of purchased natural gas — Sales of purchased natural gas relates to natural gas acquired from third parties and which is subsequently sold in connection with certain of our marketing activities. Sales of purchased natural gas were $75 million for the three months ended June 30, 2022, an increase of $43 million, or 134% from $32 million during the three months ended March 31, 2022. The increase was primarily the result of higher volumes sold and higher natural gas prices. Our natural gas sales net of related purchased natural gas expense were $8 million for the three months ended June 30, 2022 compared to $11 million for the three months ended March 31, 2022.

Electricity sales — Electricity sales increased by $15 million to $49 million for the three months ended June 30, 2022 compared to $34 million for the three months ended March 31, 2022. The increase was predominantly due to higher electricity prices resulting from higher natural gas prices.

Other revenue — Other revenue decreased to $5 million in the three months ended June 30, 2022, from $21 million for the three months ended March 31, 2022. The decrease was primarily due to increased sales of purchased NGL volumes in the first quarter of 2022 in order to meet our delivery commitments while one of our cryogenic gas processing facilities was down for planned maintenance.

The following table presents our operating and non-operating expenses and income for the three months ended June 30, 2022 and March 31, 2022:


	Three months ended
	June 30, 2022		March 31, 2022
	(in millions)
Operating expenses
Energy operating costs	$	57	$	53
Gas processing costs	4		5
Non-energy operating costs	129		124
General and administrative expenses	56		48
Depreciation, depletion and amortization	50		49
Asset impairments	2		—
Taxes other than on income	42		34
Exploration expense	1		1
Purchased natural gas expense	67		21
Electricity generation expenses	33		24
Transportation costs	12		12
Accretion expense	11		11
Other operating expenses, net	9		14
Total operating expenses	473		396
Net gain on asset divestitures	4		54
Operating income (loss)	278		(189)

Non-operating (expenses) income
Reorganization items, net	—		—
Interest and debt expense, net	(13)		(13)

Other non-operating expenses, net	1		1
Income (loss) before income taxes	266		(201)
Income tax (provision) benefit	(76)		26
Net income (loss)	$	190	$	(175)

Energy operating costs — Energy operating costs for the three months ended June 30, 2022 were $57 million, which was an increase of $4 million, or 8% from $53 million for the three months ended March 31, 2022. This increase was primarily a result of higher prices for purchased natural gas, which we use to generate electricity for our operations, and for purchased electricity.

Non-energy operating costs — Non-energy operating costs for the three months ended June 30, 2022 were $129 million, which was an increase of $5 million or 4% from $124 million for the three months ended March 31, 2022. This increase was primarily a result of higher compensation-related expenses and increased downhole maintenance activity.

General and administrative (G&A) expenses — General and administrative expenses increased $8 million to $56 million for the three months ended June 30, 2022 compared to $48 million for the three months ended March 31, 2022 primarily as a result of increased compensation-related increases and additional headcount as shown in the table below.


	Three months ended
	June 30, 2022		March 31, 2022
	(in millions)
G&A – E&P, corporate and other	$	52	$	47
G&A – Carbon management business	4		1
Total general and administrative expenses	$	56	$	48

Taxes other than on income — Taxes other than on income increased $8 million to $42 million for the three months ended June 30, 2022 compared to $34 million for the three months ended March 31, 2022. The increase primarily relates to the rate applied to assess taxes on our oil and natural gas production.

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 $67 million for the three months ended June 30, 2022, which was an increase of $46 million, or 219% from $21 million for the three months ended March 31, 2022. The increase was predominantly the result of higher prices and higher volumes purchased in the three months ended June 30, 2022 compared to the three months ended March 31, 2022.

Net gain on asset divestitures – Net gain on asset divestitures for the three months ended June 30, 2022 was $4 million compared to $54 million for the three months ended March 31, 2022. The net gain on asset divestitures for the three months ended June 30, 2022 relates to additional earn-out consideration related to our Ventura basin divestitures. In the three months ended March 31, 2022, the net gain on asset divestitures primarily related to the sale of our 50% non-operated working interest in certain horizons within our Lost Hills field. We also recognized a gain on the sale of certain Ventura basin assets. For more information on our asset divestitures, see Part I, Item 1 – Financial Information, Note 7 Divestitures and Acquisitions and Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions in our 2021 Annual Report.

Income taxes – The income tax provision for the three months ended June 30, 2022 was $76 million (effective tax rate of 29%), compared to an income tax benefit of $26 million (effective tax rate of 13%) for the three months ended March 31, 2022. The income tax benefit for the three months ended March 31, 2022 included a $31 million charge for a valuation allowance recorded at the time of our Lost Hills divestiture. See Part I, Item 1 – Financial Statements, Note 12 Income Taxes for more information.

Six months ended June 30, 2022 compared to June 30, 2021

The following table presents our operating revenues for the six months ended June 30, 2022 and 2021:


	Six months ended June 30,
	2022		2021
	(in millions)
Oil, natural gas and NGL sales	$	1,346	$	910
Net loss from commodity derivatives	(662)		(478)
Sales of purchased natural gas	107		146
Electricity sales	83		66
Other revenue	26		23
Total operating revenues	$	900	$	667

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $1,346 million for the six months ended June 30, 2022, which is an increase of $436 million compared to $910 million for the same period of 2021. This increase was due to higher realized prices, which was partially offset by lower production, as reflected in the following table:


	Oil		NGLs		Natural Gas		Total
	(in millions)
Six months ended June 30, 2021	$	711	$	107	$	92	$	910
Changes in realized prices	428		59		99		586
Changes in production	(106)		(27)		(17)		(150)
Six months ended June 30, 2022	$	1,033	$	139	$	174	$	1,346

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

The effect of cash settlements on our commodity derivative contracts is not included in the table above. Payments on commodity derivatives were $422 million for the six months ended June 30, 2022 compared to payments of $121 million for the same period of 2021. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $135 million or 17% for the six months ended June 30, 2022 compared to the same prior-year period.

Net loss from commodity derivatives — Net loss from commodity derivatives was $662 million for the six months ended June 30, 2022 compared to a net loss of $478 million for the same prior year period. The increase in the net loss primarily resulted from settlement payments due to a higher price environment. 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 as shown in the table below:


	Six months ended June 30,
	2022		2021
	(in millions)
Non-cash commodity derivative loss	$	(240)	$	(357)


Net cash payments on settled commodity derivatives	(422)		(121)

Net loss from commodity derivatives	$	(662)	$	(478)

Sales of purchased natural gas — Sales of purchased natural gas relates to natural gas acquired from third parties and which is subsequently sold in connection with certain of our marketing activities. Sales of purchased natural gas were $107 million for the six months ended June 30, 2022, a decrease of $39 million, or 27% from $146 million during the same period of 2021. The decrease was predominantly the result of lower volumes, partially offset by higher prices. Our natural gas sales net of related purchased natural gas expense was $19 million for the six months ended June 30, 2022 compared to $55 million for the same period of 2021.

Electricity sales — Electricity sales increased by $17 million to $83 million for the six months ended June 30, 2022 compared to $66 million for the same prior-year period. The increase was predominantly due to higher electricity prices resulting from higher natural gas prices.

The following table presents our operating and non-operating expenses for the six months ended June 30, 2022 and 2021:



	Six months ended June 30,
	2022		2021
	(in millions)
Operating expenses
Energy operating costs	$	110	$	85
Gas processing costs	9		11
Non-energy operating costs	253		237
General and administrative expenses	104		96
Depreciation, depletion and amortization	99		106
Asset impairments	2		3
Taxes other than on income	76		77
Exploration expense	2		4
Purchased natural gas expense	88		91
Electricity generation expenses	57		41
Transportation costs	24		26
Accretion expense	22		26
Other operating expenses, net	23		27
Total operating expenses	869		830
Net gain on asset divestitures	58		—
Operating income (loss)	89		(163)

Non-operating (expenses) income
Reorganization items, net	—		(4)
Interest and debt expense, net	(26)		(26)
Net loss on early extinguishment of debt	—		(2)
Other non-operating expenses, net	2		(1)
Income (loss) before income taxes	65		(196)
Income tax provision	(50)		—
Net income (loss)	$	15	$	(196)

Energy operating costs — Energy operating costs for the six months ended June 30, 2022 were $110 million, which was an increase of $25 million, or 29% from $85 million for the same period of 2021. 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 six months ended June 30, 2022 were $253 million, which was an increase of $16 million, or 7% from $237 million for the same period of 2021. This increase was primarily a result of higher prices for purchased natural gas which we use to generate steam for our steamfloods.

General and administrative expenses — General and administrative expenses increased $8 million to $104 million for the six months ended June 30, 2022 compared to $96 million for the six months ended June 30, 2021 as a result of increased compensation-related expenses and additional headcount as shown in the table below.


	Six months ended June 30,
	2022		2021
	(in millions)
G&A – E&P, corporate and other	$	99	$	96
G&A – Carbon management business	5		—
Total general and administrative expenses	$	104	$	96

Electricity generation expenses — Electricity generation expenses were $57 million for the six months ended June 30, 2022, which is an increase of $16 million, or 39%, from $41 million in the same prior-year period. The increase was predominantly due to higher electricity prices resulting from higher natural gas prices.

Net gain on asset divestitures – Net gain on asset divestitures for the six months ended June 30, 2022 was $58 million primarily relates to the sale of our 50% non-operated working interest in certain horizons within our Lost Hills field. We also recognized a gain on the sale of certain Ventura basin assets during the six months ended June 30, 2022. For more information on our asset divestitures, see Part I, Item 1 – Financial Information, Note 7 Divestitures and Acquisitions and Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions in our 2021 Annual Report.

Income taxes – The income tax provision for the six months ended June 30, 2022 was $50 million (effective tax rate of 77%), which includes a $31 million charge for a valuation allowance recorded at the time of our Lost Hills divestiture. See Part I, Item 1 – Financial Statements, Note 12 Income Taxes for more information. Realization of our deferred tax assets is subjective and remains dependent on a number of factors including our ability to generate sufficient taxable income, including capital gains, in future periods. We did not recognize an income tax benefit in the six months ended June 30, 2021 due to a full valuation allowance against our net deferred tax assets at that time.

Liquidity and Capital Resources

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 which matures in April 2024. 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 three months ended June 30, 2022 were for capital investments, dividends and repurchases of our common stock.

The following table summarizes our liquidity:



	June 30, 2022
	(in millions)
Cash	$	324
Revolving Credit Facility:
Borrowing capacity	552
Outstanding letters of credit	(136)
Availability	$	416

Liquidity	$	740

On April 29, 2022, the borrowing base under our Revolving Credit Facility was reaffirmed at $1.2 billion. Our Revolving Credit Facility was amended as of April 29, 2022. See Part I, Item 1 – Financial Statements, Note 6 Debt for more information regarding this amendment.

At current commodity prices and based upon our planned 2022 capital program described below, we expect to generate operating cash flow to support and invest in our core assets and preserve financial flexibility. We regularly review our financial position and evaluate whether to (i) increase investments in our drilling program to accelerate value, (ii) return available cash to shareholders through dividends or stock buybacks to the extent permitted under our Revolving Credit Facility and Senior Notes indenture, (iii) advance carbon management activities, or (iv) maintain cash on our balance sheet. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.

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. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. Prior to May 2022, our Revolving Credit Facility required us to maintain certain levels of hedges regardless of our leverage. We also entered into incremental hedges above and beyond these requirements for certain time periods. In certain circumstances, these hedges (including hedges entered into by us in 2020 to comply with covenants in our Revolving Credit Facility) prevent us from realizing the full benefits of price increases. Following recent amendments to our Revolving Credit Facility in April 2022, we are only required to maintain hedges in the event the ratio of our consolidated total secured debt to consolidated EBITDAX as defined in our Credit Agreement exceeds 1:1. We will continue to evaluate our hedging strategy based on prevailing market prices and conditions.

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 months ended June 30, 2022. See Part I, Item 1 – Financial Statements, Note 9 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of June 30, 2022 and Part I, Item 1 – Financial Statements, Note 6 Debt for information for more information on an amendment to the hedging requirements included in our Revolving Credit Facility.

2022 Capital Program

Our capital program is dynamic in response to oil market volatility while focusing on maintaining our oil production and strong liquidity and maximizing our free cash flow. During the second half of 2022, we expect to run five drilling rigs in the Elk Hills, Buena Vista and Wilmington fields.

We are increasing our 2022 capital program to a range of $380 million to $410 million from $340 million to $385 million. We have and will likely continue to experience cost increases related to our drilling program due to inflationary pressures, including for items such as oilfield tubular goods (tubing, casing and pipe), fuel and drilling services. We increased our 2022 capital program for inflation and these cost increases could also impact our capital program in 2023 and beyond. Additionally, in response to the continued strong commodity environment, we are adding to our workover program for natural gas assets located in the Sacramento Basin and the Buena Vista field. Finally, we have increased our capital program for our carbon management activities.

This level of expected spending is consistent with our capital allocation strategy. Following the joint venture with Brookfield, we anticipate that the percentage of operating cash flow previously designated for advancing decarbonization and other emission reducing projects will now be available for other corporate purposes, such as shareholder returns and other strategic opportunities. See a summary of our Business Strategy in Part I, Item 1 & 2 – Business and Properties, in our 2021 Annual Report.

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:


	2022 Full Year Estimate	Six months ended June 30, 2022
	(in millions)
Oil and natural gas operations, corporate and other	$360 - $380	$	186
Carbon management business	20 - 30	11

Total Capital	$380 - $410	$	197

Cash Flow Analysis

Cash flows from operating activities — Our net cash provided by operating activities is subject to many variables, including changes in commodity prices. Commodity price movements may also lead to other changes in our business, including adjustments to our capital program.

For the six months ended June 30, 2022, our operating cash flow increased 24%, or $67 million, to $341 million from $274 million in the same prior period of 2021. Net cash used in operating activities for the six months ended June 30, 2022 included $7 million related to our carbon management business. We did not have operations related to our carbon management business for the six months ended June 30, 2021.

The increases in operating cash flow for the six months ended June 30, 2022 primarily relates to higher average realized prices (including the effects of settlements on our commodity derivatives) in 2022 compared to the same prior-year period. This increase was partially offset by lower production volumes in 2022 as compared to the same period in 2021. The increase in our revenue from oil, natural gas and NGL sales was partially offset by an increase in operating costs primarily related to higher prices for purchased natural gas and electricity used in our operations.

Cash flows from investing activities — The following table provides a comparative summary of net cash used in investing activities:



	Six months ended June 30,
		2022		2021
		(in millions)
Capital investments		$	(197)	$	(77)
Changes in accrued capital investments		9		13
Proceeds from divestitures		76		2
Acquisitions		(17)		(1)

Net cash used in investing activities		$	(129)	$	(63)

Net cash used in investing activities for the six months ended June 30, 2022 included $11 million related to our carbon management business. We did not have investing activities related to our carbon management business for the six months ended June 30, 2021.

Cash flows from financing activities — The following table provides a comparative summary of net cash used in financing activities:


	Six months ended June 30,
		2022		2021
		(in millions)
Debt transactions, net		$	—	$	(12)
Distributions paid to a noncontrolling interest holder		—		(31)
Repurchases of common stock		(167)		(45)
Common stock dividends		(26)		—

Net cash used in financing activities		$	(193)	$	(88)

Lawsuits, Claims, Commitments and Contingencies

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at June 30, 2022 and December 31, 2021 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.

See Part I, Item 1 – Financial Statements, Note 8 Lawsuits, Claims, Commitments and Contingencies for further information.

Critical Accounting Estimates and Significant Accounting and Disclosure Changes

There have been no changes to our critical accounting estimates, which are summarized in Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates of our 2021 Annual Report. See Part I, Item 1 – Financial Statements, Note 2 Accounting and Disclosure Changes for a discussion of new accounting standards.

Forward-Looking Statements

This document contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

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

•fluctuations in commodity prices and the potential for sustained low oil, natural gas and natural gas liquids prices;

•equipment, service or labor price inflation or unavailability;

•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;

•availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities and carbon management projects;

•changes in business strategy and our capital plan;

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

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

•the recoverability of resources and unexpected geologic conditions;

•our ability to utilize storage capacity of the 26R storage reservoir consistent with the Joint Venture and Investment Agreement through either storage only contracts or as part of an integrated project;

•our ability to identify and develop projects that are acceptable to the JV;

•our ability to successfully execute on the construction and other aspects of the infrastructure projects and enter into third party contracts on contemplated terms;

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

•our ability to finance and implement our carbon capture and storage projects, including the development of projects contemplated as part of the strategic partnership with Brookfield;

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

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

•production-sharing contracts' effects on production and operating costs;

•limitations on our financial flexibility due to existing and future debt;

•insufficient cash flow to fund planned investments, interest payments on our debt, stock repurchases or changes to our capital plan;

•insufficient capital or liquidity 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;

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

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

•our ability to successfully gather and verify data regarding emissions, our environmental impacts and other 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;

•changes in the intensity of competition in the oil and gas industry;

•effects of hedging transactions;

•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

•other factors discussed in Part I, Item 1A – Risk Factors.

We caution you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and we undertake no obligation to update this information. This document 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 months ended June 30, 2022, 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 2021 Annual Report.

Commodity Price Risk

Our financial results are sensitive to fluctuations in oil, NGL and natural gas prices. These commodity price changes also impact the volume changes under PSCs. We maintain a commodity hedging program primarily focused on hedging crude oil sales to help protect our cash flows, margins and capital program from the volatility of crude oil prices. As of June 30, 2022, we had net liabilities of $596 million for our derivative commodity positions which are carried at fair value. For more information on our derivative positions as of June 30, 2022, refer to Part I, Item 1 – Financial Statements, Note 9 Derivatives. We have price exposure for natural gas we purchase and use in our business. We used natural gas to generate electricity for our operations and higher natural gas prices will increase our electricity costs.

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. Counterparty credit limits have been established based upon the financial health of our counterparties, and these limits are actively monitored. In the event counterparty credit risk is heightened, we may request collateral and accelerate payment dates. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.

As of June 30, 2022, the majority of our credit exposure was with investment-grade counterparties. We believe exposure to counterparty credit-related losses related to our business at June 30, 2022 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

Interest-Rate Risk

Changes in interest rate may affect the amount of interest we pay on our long-term debt. We had no variable-rate debt outstanding as of June 30, 2022. Our Senior Notes bear interest at a fixed rate of 7.125% per annum.

Item 4 Controls and Procedures

Our Chief Executive Officer and our Chief Financial Officer supervised and participated in management's evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2022.

There were no changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the three months ended June 30, 2022 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION

Item 1Legal Proceedings

For additional information regarding legal proceedings, see Item 1 – Financial Statements, Note 8 Lawsuits, Claims, Commitments and Contingencies in the Notes to the Condensed Consolidated Financial Statements included in Part I of this Form 10-Q, Part I, Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Lawsuits, Claims, Commitments and Contingencies in this Form 10-Q, and Part I, Item 3, Legal Proceedings in our 2021 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 2021 Annual Report. There were no material changes to those risk factors during the six months ended June 30, 2022.

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds

Our Board of Directors authorized a Share Repurchase Program to acquire up to $650 million of our common stock through June 30, 2023. The repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time. Shares repurchased are held as treasury stock.

Our share repurchase activity for the three months ended June 30, 2022 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, 2022 - April 30, 2022	452,035	$	44.17	452,035	$	—
May 1, 2022 - May 31, 2022	820,660	$	41.52	820,660	—
June 1, 2022 - June 30, 2022	982,750	$	42.70	982,750	—
Total	2,255,445	$	42.57	2,255,445	$	—

(a)The dollar value of shares that may yet be purchased under the Share Repurchase Program totaled $335 million as of June 30, 2022.

Item 5 Other Disclosures

None.

Item 6 Exhibits


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

3.2			Certificate of Amendment of Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 t o Registrant's Current Report on Form 8-K filed on M ay 6, 2022 and incorporated herein by reference).

3.3			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			Third Amendment to the Credit Agreement, dated April 29, 2022, by and among California Resources Corporation, as the Borrower, the credit parties party thereto, the several lenders from time to time parties thereto and Citibank, N.A. as administrative agent (fi led as E xhibit 10.2 to the Regi strant's Quarter ly Report on Form 10-Q filed May 5, 2022 and incorporated herein b y reference ).

10.2			Employee Stock Purchase Plan (filed as Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on May 6, 2022 and incorporated herein by reference).

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

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

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

101.INS*			Inline XBRL Instance Document.

101.SCH*			Inline XBRL Taxonomy Extension Schema Document.

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

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

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

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

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

* - Filed herewith

SIGNATURES

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


			CALIFORNIA RESOURCES CORPORATION


DATE:	August 4, 2022	/s/ Noelle M. Repetti
		Noelle M. Repetti
		Senior Vice President and Controller
		(Principal Accounting Officer)