crc-20220930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 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 September 30, 2022 was 73,470,932.

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	24
	General	24
	Carbon TerraVault Joint Venture	24
	Dividends	25
	Share Repurchase Program	25
	Divestitures and Acquisitions	25
	Business Environment and Industry Outlook	25
	Regulatory Updates	27
	Production	29
	Prices and Realizations	31
	Statements of Operations Analysis	33
	Liquidity and Capital Resources	39
	2022 Capital Program	40
	Lawsuits, Claims, Commitments and Contingencies	41
	Critical Accounting Estimates and Significant Accounting and Disclosure Changes	42
	Forward-Looking Statements	43
Item 3	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4	Controls and Procedures	45

Part II
Item 1	Legal Proceedings	46
Item 1A	Risk Factors	46
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 5	Other Disclosures	46
Item 6	Exhibits	47

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.

•MMT - Million metric tons

•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 September 30, 2022 and December 31, 2021

(in millions, except share data)



	September 30,		December 31,
	2022		2021
CURRENT ASSETS
Cash and cash equivalents	$	358	$	305
Trade receivables	289		245
Inventories	59		60
Assets held for sale	3		22
Receivable from affiliate	32		—
Other current assets	143		121
Total current assets	884		753
PROPERTY, PLANT AND EQUIPMENT	3,126		2,845
Accumulated depreciation, depletion and amortization	(392)		(246)
Total property, plant and equipment, net	2,734		2,599
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	14		—
DEFERRED TAX ASSET	230		396
OTHER NONCURRENT ASSETS	124		98
TOTAL ASSETS	$	3,986	$	3,846


CURRENT LIABILITIES



Accounts payable	305		266
Liabilities associated with assets held for sale	2		21
Fair value of derivative contracts	254		270
Accrued liabilities	371		297

Total current liabilities	932		854
NONCURRENT LIABILITIES
Long-term debt, net	591		589

Fair value of derivative contracts	26		132
Asset retirement obligations	397		438
Other long-term liabilities	185		145



STOCKHOLDERS' EQUITY
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at September 30, 2022 and December 31, 2021	—		—
Common stock (200,000,000 shares authorized at $0.01 par value) (83,406,002 and 83,389,210 shares issued; 73,470,932 and 79,299,222 shares outstanding at September 30, 2022 and December 31, 2021)	1		1
Treasury stock (9,935,070 shares held at cost at September 30, 2022 and 4,089,988 shares held at cost at December 31, 2021)	(395)		(148)
Additional paid-in capital	1,301		1,288
Retained earnings	876		475
Accumulated other comprehensive income	72		72


Total stockholders' equity	1,855		1,688
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,986	$	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 nine months ended September 30, 2022 and 2021

(dollars in millions, except per share data)



	Three months ended September 30,				Nine months ended September 30,
	2022		2021		2022		2021
REVENUES
Oil, natural gas and NGL sales	$	680	$	549	$	2,026	$	1,459
Net gain (loss) from commodity derivatives	243		(125)		(419)		(603)
Sales of purchased natural gas	113		95		220		241
Electricity sales	88		65		171		131
Other revenue	1		4		27		27
Total operating revenues	1,125		588		2,025		1,255

OPERATING EXPENSES
Operating costs	214		190		586		523
General and administrative expenses	59		51		163		147
Depreciation, depletion and amortization	50		54		149		160
Asset impairments	—		25		2		28
Taxes other than on income	44		36		120		113
Exploration expense	1		2		3		6
Purchased natural gas expense	98		53		186		144
Electricity generation expenses	42		29		99		70
Transportation costs	13		11		37		37
Accretion expense	10		13		32		39
Other operating expenses, net	5		4		28		31
Total operating expenses	536		468		1,405		1,298
Net gain on asset divestitures	2		2		60		4

OPERATING INCOME (LOSS)	591		122		680		(39)

NON-OPERATING (EXPENSES) INCOME
Reorganization items, net	—		(1)		—		(5)
Interest and debt expense, net	(13)		(14)		(39)		(40)
Net loss on early extinguishment of debt	—		—		—		(2)
Other non-operating expenses, net	1		—		3		(3)
INCOME (LOSS) BEFORE INCOME TAXES	579		107		644		(89)
Income tax provision	(153)		—		(203)		—
NET INCOME (LOSS)	426		107		441		(89)



Net income attributable to noncontrolling interests	—		(4)		—		(13)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	426	$	103	$	441	$	(102)

Net income (loss) attributable to common stock per share
Basic	$	5.75	$	1.26	$	5.77	$	(1.23)
Diluted	$	5.58	$	1.25	$	5.62	$	(1.23)

Weighted-average common shares outstanding
Basic	74.1		81.6		76.4		82.6
Diluted	76.3		82.4		78.5		82.6

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 nine months ended September 30, 2022 and 2021

(in millions)



	Three months ended September 30,				Nine months ended September 30,
	2022		2021		2022		2021
Net income (loss)	$	426	$	107	$	441	$	(89)
Net income attributable to noncontrolling interest	—		(4)		—		(13)
Other comprehensive income:
Actuarial gain associated with pension and postretirement plans(a)	—		17		—		17
Net prior service cost credit(a)	—		65		—		65
Comprehensive income (loss) attributable to common stock	$	426	$	185	$	441	$	(20)

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

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 nine months ended September 30, 2022

(in millions)


	Three months ended September 30, 2022
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, June 30, 2022	$	1	$	(315)	$	1,296	$	463	$	72	$	1,517
Net income	—		—		—		426		—		426

Share-based compensation	—		—		6		—		—		6



Repurchases of common stock	—		(80)		—		—		—		(80)

Cash dividend ($0.17 per share)	—		—		—		(13)		—		(13)
Other	—		—		(1)		—		—		(1)
Balance, September 30, 2022	$	1	$	(395)	$	1,301	$	876	$	72	$	1,855


	Nine months ended September 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	—		—		—		441		—		441

Share-based compensation	—		—		14		—		—		14



Repurchases of common stock	—		(247)		—		—		—		(247)

Cash dividends ($0.17 per share)	—		—		—		(40)		—		(40)
Other	—		—		(1)		—		—		(1)
Balance, September 30, 2022	$	1	$	(395)	$	1,301	$	876	$	72	$	1,855

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 nine months ended September 30, 2021

(in millions)


	Three months ended September 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, June 30, 2021	$	1	$	(45)	$	1,273	$	(328)	$	(8)	$	893	$	22	$	915
Net (loss) income	—		—		—		103		—		103		4		107

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



Repurchases of common stock	—		(39)		—		—		—		(39)		—		(39)
Issuance of common stock	—		—		2		—		—		2		—		2

Other comprehensive income	—		—		—		—		82		82		—		82
Balance, September 30, 2021	$	1	$	(84)	$	1,286	$	(225)	$	74	$	1,052	$	—	$	1,052


	Nine months ended September 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	—		—		—		(102)		—		(102)		13		(89)

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



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

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

For the three and nine months ended September 30, 2022 and 2021

(in millions)



	Three months ended September 30,				Nine months ended September 30,
	2022		2021		2022		2021
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)	$	426	$	107	$	441	$	(89)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	50		54		149		160
Deferred income tax provision	137		—		166		—
Asset impairments	—		25		2		28
Net (gain) loss from commodity derivatives	(243)		125		419		603
Net payments on settled commodity derivatives	(182)		(99)		(604)		(220)
Net loss on early extinguishment of debt	—		—		—		2

Net gain on asset divestitures	(2)		(2)		(60)		(4)



Other non-cash charges to income, net	15		17		42		46
Changes in operating assets and liabilities, net	34		(45)		21		(70)
Net cash provided by operating activities	235		182		576		456

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(107)		(51)		(304)		(128)
Changes in accrued capital investments	(4)		5		5		18
Proceeds from asset divestitures, net	3		11		79		13
Acquisitions	—		(53)		(17)		(53)
Distribution related to the Carbon TerraVault JV	12		—		12		—
Capitalized joint venture transaction costs	(12)		—		(12)		—
Other	(1)		—		(1)		(1)
Net cash used in investing activities	(109)		(88)		(238)		(151)

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	—		—		—		(13)
Repayment of Second Lien Term Loan	—		—		—		(200)
Repayment of EHP Notes	—		—		—		(300)

Repurchases of common stock	(80)		(39)		(247)		(84)
Common stock dividends	(13)		—		(39)		—
Proceeds from warrants exercised	—		2		—		2


Distributions paid to a noncontrolling interest holder	—		(19)		—		(50)
Issuance of common stock	1		—		1		—

Net cash used in financing activities	(92)		(56)		(285)		(144)
Increase in cash and cash equivalents	34		38		53		161
Cash and cash equivalents—beginning of period	324		151		305		28
Cash and cash equivalents—end of period	$	358	$	189	$	358	$	189

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

September 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. We are in the early stages of permitting several carbon capture and storage projects in California. Our subsidiary Carbon TerraVault is expected to build, install, operate and maintain CO2 capture equipment, transportation assets and storage facilities in California. In August 2022, Carbon TerraVault entered into a joint venture with BGTF Sierra Aggregator LLC (Brookfield) to pursue certain of these opportunities (Carbon TerraVault JV). See Note 2 Accounting Policy and Disclosure Changes for our accounting policy related to joint ventures and investments in unconsolidated subsidiaries and Note 8 Investments and Related Party Transactions for more information on the Carbon TerraVault JV. Separately, we are evaluating the feasibility of a carbon capture system to be located at our Elk Hills power plant.

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 POLICY AND DISCLOSURE CHANGES

Accounting Policy Update

Joint Ventures and Investments in Unconsolidated Subsidiaries

We may enter into joint ventures that are considered to be a variable interest entity (VIE). A VIE is a legal entity that possesses any of the following conditions: the entity's equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity's economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity's expected losses or the right to receive the legal entity's expected residual returns. We consolidate a VIE if we determine that we have (i) the power to direct the activities of the VIE that most significantly impact its economic performance and (ii) the obligation to absorb losses or the right to receive benefits from the VIE that are more than insignificant to the VIE. If an entity is determined to be a VIE but we do not have a controlling interest, the entity is accounted for under either the cost or equity method depending on whether we exercise significant influence. See Note 8 Investments and Related Party Transactions for more information on the Carbon TerraVault JV. These evaluations are highly complex and involve management judgment and may involve the use of estimates and assumptions based on available information. The evaluation requires continual assessment.

Investments in unconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred, which is other than temporary.

Recently Adopted Accounting and Disclosure Changes

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 the February 2022 amendment of our Revolving Credit Facility described in Note 6 Debt 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:



	September 30,		December 31,
	2022		2021
	(in millions)
Amounts due from joint interest partners	$	39	$	47

Fair value of derivative contracts	64		6
Prepaid expenses	14		16
Greenhouse gas allowances	14		31
Natural gas margin deposits	5		12
Other	7		9
Other current assets	$	143	$	121

Other noncurrent assets — Other noncurrent assets includes the following:



	September 30,		December 31,
	2022		2021
	(in millions)
Operating lease right-of-use assets	$	40	$	43
Deferred financing costs - Revolving Credit Facility	7		11
Emission reduction credits	11		11
Prepaid power plant maintenance	26		21
Fair value of derivative contracts	25		1
Deposits and other	15		11
Other noncurrent assets	$	124	$	98

Accrued liabilities — Accrued liabilities includes the following:



	September 30,		December 31,
	2022		2021
	(in millions)
Accrued employee-related costs	$	64	$	61
Accrued taxes other than on income	43		30
Asset retirement obligations	78		51
Accrued interest	9		19
Lease liability	12		11

Premiums due on derivative contracts	64		57
Liability for settlement payments on derivative contracts	48		25
Amounts due under production-sharing contracts	9		14
Income taxes payable	17		—
Marketing prepayments	4		5
Other	23		24
Accrued liabilities	$	371	$	297

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



	September 30,		December 31,
	2022		2021
	(in millions)
Compensation-related liabilities	$	34	$	38
Postretirement and pension benefit plans	54		59
Lease liability	32		37

Premiums due on derivative contracts	13		5
Contingent liability related to Carbon TerraVault JV put and call rights	46		—
Other	6		6
Other long-term liabilities	$	185	$	145

NOTE 4 SUPPLEMENTAL CASH FLOW INFORMATION

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

Interest paid, net of capitalized amounts was $21 million and $23 million for the three months ended September 30, 2022 and 2021, respectively. Interest paid, net of capitalized amounts was $43 million and $27 million for the nine months ended September 30, 2022 and 2021, respectively.

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

For the three and nine months ended September 30, 2022, we made a non-cash contribution of $2 million to the Carbon TerraVault JV to satisfy a capital call. See Note 8 Investments and Related Party Transactions for more information on our joint venture.

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:



	September 30,		December 31,
	2022		2021
	(in millions)
Materials and supplies	$	53	$	54
Finished goods	6		6
Inventories	$	59	$	60

NOTE 6 DEBT

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



	September 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 $602 million, which we are permitted to increase if we obtain additional commitments from new or existing lenders. This amount includes $110 million of additional commitments from new lenders that joined this facility in February 2022 and September 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 October 25, 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.

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). 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.

In April 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.

At September 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 September 30, 2022 and December 31, 2021 was approximately $564 million and $623 million, respectively. We estimate fair value based on prices known from market transactions (using Level 1 inputs on the fair value hierarchy).

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 nine months ended September 30, 2022, we recorded a gain of $2 million and $12 million, respectively, related to the sale of certain Ventura basin assets. We did not close transactions during the three months ended September 30, 2022. The amount recognized in the three and nine months ended September 30, 2022 included $2 million and $6 million, respectively, of 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 well abandonment which we expect to release 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 September 30, 2022. 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.

The closing of the sale of our remaining assets in the Ventura basin is subject to final approval from the State Lands Commission, which we expect to receive prior to the end of the first quarter of 2023. These remaining assets, consisting of property, plant and equipment and associated asset retirement obligations, are classified as held for sale on our condensed consolidated balance sheet as of September 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. We also leased back a portion of the building with a term of 18 months. In the second quarter of 2022, prior to the sale we recorded a $2 million impairment charge to write down the carrying value to fair value, which was determined based on a market approach (using Level 3 inputs in the fair value hierarchy).

In the three months ended September 30, 2021, we also recorded an impairment charge of $25 million related to the write-down of the same commercial office building to fair value, which was determined based on a market approach (using Level 3 inputs in the fair value hierarchy). The decline in value of the commercial office building at that time primarily related to limited demand for office space of this size and type in the Bakersfield market and general trends in commercial real estate due to the COVID-19 pandemic. We do not own any other commercial office buildings.

Other

During the nine months ended September 30, 2022, we sold non-core assets recognizing a $1 million loss.

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

Acquisitions

During the nine months ended September 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 September 30, 2022.

In August 2021, we purchased the 90% working interest held by Macquarie Infrastructure and Real Assets Inc (MIRA) in certain oil and natural gas properties in the San Joaquin basin for $53 million, before purchase price adjustments and transaction costs. Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions in our 2021 Annual Report for more information on the acquisition. There were no other acquisitions for the three and nine months ended September 30, 2021.

NOTE 8 INVESTMENTS AND RELATED PARTY TRANSACTIONS

In August 2022, we entered into the Carbon TerraVault JV with Brookfield for the development of a carbon management business in California. We hold a 51% interest in the Carbon TerraVault JV and Brookfield holds a 49% interest. We determined that the Carbon TerraVault JV is a VIE; however, we share decision-making power with Brookfield on matters that most significantly impact the economic performance of the joint venture. Therefore, we account for our investment in the Carbon TerraVault JV under the equity method of accounting. See Note 2 Accounting Policy and Disclosure Changes for more information on the VIE consolidation model. Transactions between us and the Carbon TerraVault JV are related party transactions.

As part of the formation of the Carbon TerraVault JV, we contributed rights to inject CO2 into the 26R reservoir in our Elk Hills field for permanent CO2 storage (26R reservoir) and Brookfield committed to make an initial investment of $137 million, payable in three equal installments with the last two installments subject to the achievement of certain milestones. Brookfield contributed the first $46 million installment of their initial investment to the Carbon TerraVault JV during the three months ended September 30, 2022. This amount may, at our sole discretion, be distributed to us or used to satisfy future capital contributions, among other items. During the three months ended September 30, 2022, $12 million of the initial investment was distributed to us (and used to pay transaction costs related to the formation of the joint venture) and $2 million was used to satisfy a capital call. This $14 million is reflected on our condensed consolidated balance sheet as an investment in an unconsolidated subsidiary at September 30, 2022. The remaining $32 million is reported as a receivable from affiliate on our condensed consolidated balance sheet as of September 30, 2022. Because the parties have certain put and call rights with respect to the 26R reservoir, if certain milestones are not met, the $46 million initial investment by Brookfield is reflected as a contingent liability in other long-term liabilities on our condensed consolidated balance sheet as of September 30, 2022.

The Carbon TerraVault JV has an option to participate in certain projects that involve the capture, transportation and storage of CO2 in California. This option expires upon the earlier of (1) August 2027, (2) when a final investment decision has been approved by the Carbon TerraVault JV for storage projects representing in excess of 5 million metric tons per annum (MMTPA) in the aggregate, or (3) when Brookfield has made contributions to the joint venture in excess of $500 million (unless Brookfield elects to increase its commitment).

Our proportionate share of the net loss generated by the Carbon TerraVault JV for the three and nine months ended September 30, 2022 was insignificant due to the start-up nature of the joint venture.

NOTE 9 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

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

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances for these items at September 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.

NOTE 10 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 nine months ended September 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 September 30, 2022:


	Q4 2022		Q1 2023		Q2 2023		Q3 2023		Q4 2023		2024
Sold Calls
Barrels per day	25,167		18,322		17,837		17,363		5,747		—
Weighted-average price per barrel	$	57.82	$	57.28	$	60.00	$	57.06	$	57.06	$	—

Swaps
Barrels per day	17,263		14,620		14,475		14,697		24,094		1,492
Weighted-average price per barrel	$	58.79	$	67.36	$	66.36	$	66.27	$	69.14	$	79.06

Net Purchased Puts(a)
Barrels per day	25,167		18,322		17,837		17,363		5,747		1,724
Weighted-average price per barrel	$	64.47	$	76.25	$	76.25	$	76.25	$	76.25	$	75.00

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

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

We held natural gas swaps for 25,000 MMBTU per day at a weighted-average price of $7.74 per MMBTU for the fourth quarter of 2022.

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 September 30, 2022 and December 31, 2021:


September 30, 2022
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	(in millions)
Other current assets - Fair value of derivative contracts	$	85	$	(21)	$	64
Other noncurrent assets - Fair value of derivative contracts	28		(3)		25

Liabilities
Current - Fair value of derivative contracts	(275)		21		(254)
Noncurrent - Fair value of derivative contracts	(29)		3		(26)
	$	(191)	$	—	$	(191)


December 31, 2021
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	(in millions)
Other current assets - Fair value of derivative contracts	$	33	$	(27)	$	6
Other noncurrent assets - Fair value of derivative contracts	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 nine months ended September 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 11 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) were calculated using the treasury stock method for the three and nine months ended September 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 nine months ended September 30, 2022 and 2021:



	Three months ended September 30,				Nine months ended September 30,
	2022		2021		2022		2021
	(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS
Net income (loss)	$	426	$	107	$	441	$	(89)
Less: net income attributable to noncontrolling interests	—		(4)		—		(13)
Net income (loss) attributable to common stock	$	426	$	103	$	441	$	(102)



Denominator for Basic EPS
Weighted-average shares	74.1		81.6		76.4		82.6

Potential Common Shares, if dilutive:
Warrants	0.7		—		0.7		—
Restricted Stock Units	0.8		0.4		0.7		—
Performance Stock Units	0.7		0.4		0.7		—

Denominator for Diluted EPS
Weighted-average shares	76.3		82.4		78.5		82.6

EPS
Basic	$	5.75	$	1.26	$	5.77	$	(1.23)
Diluted	$	5.58	$	1.25	$	5.62	$	(1.23)

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



	Three months ended September 30,		Nine months ended September 30,
	2022	2021	2022	2021
	(in millions)
Shares issuable upon exercise of warrants(a)	—	4.3	—	4.3

Shares issuable upon settlement of RSUs	—	—	—	0.9
Shares issuable upon settlement of PSUs	—	—	—	0.6

Total antidilutive shares	—	4.3	—	5.8

(a)Diluted earnings per share for the three and nine months ended September 30, 2021 excludes 4.3 million common shares issuable upon exercise of warrants that were out-of-the-money based on the average stock price for those periods. See Note 14 Stockholders' Equity for information on the terms of the warrants.

NOTE 12 PENSION AND POSTRETIREMENT BENEFIT PLANS

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



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


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



	Nine months ended September 30,				Nine months ended September 30,
	2022				2021
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
	(in millions)				(in millions)
Service cost - benefits earned during the period	$	1	$	2	$	1	$	3
Interest cost on projected benefit obligation	1		1		1		2
Expected return on plan assets	(1)		—		(1)		—

Curtailment gain	—		—		—		(1)
Amortization of prior service cost credit	—		(5)		—		—
Net periodic benefit costs	$	1	$	(2)	$	1	$	4

We made contributions of approximately $1 million for the three months ended September 30, 2022 and contributed approximately $2 million to our defined benefit plans during the nine months ended September 30, 2022. We contributed approximately $1 million and $2 million to our defined benefit plans during the three and nine months ended September 30, 2021, respectively. We expect to satisfy minimum funding requirements with insignificant contributions to our defined benefit pension plans during the remainder of 2022.

In the third quarter of 2021, we adopted a postretirement benefit design change, which terminated the employer cost sharing for post age 65 retiree health benefits effective as of January 1, 2022. Our retiree health care benefits provided up to age 65 to current and future retirees who meet certain eligibility requirements were not affected by this change. As a result of this change, our postretirement medical benefit obligation was remeasured as of September 30, 2021. The remeasurement resulted in a decrease to the benefit obligation of $82 million with a corresponding increase to accumulated other comprehensive income. The benefit from the change in plan design will be recognized in our statement of operations over the average remaining years of future service for active employees as a component of other non-operating expenses, net. During the three and nine months ended September 30, 2022, we have recognized a benefit of $2 million and $5 million, respectively.

NOTE 13 INCOME TAXES

The difference between the U.S. federal statutory tax rate of 21% and our effective tax rate of 26% for the three months ended September 30, 2022 primarily relates to California state taxes, partially offset by the benefit of federal tax credits. The difference between the U.S. federal statutory tax rate of 21% and our effective tax rate of 32% for the nine months ended September 30, 2022 primarily relates to California state taxes and an increase in the valuation allowance related to a capital loss realized on the Lost Hills divestiture, the deductibility of which is limited to future capital gains partially offset by the benefit of federal tax credits. We did not record an income tax benefit for the three and nine months ended September 30, 2021, because we maintained 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 14 STOCKHOLDERS' EQUITY

Share Repurchase Program

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $650 million of our common stock through June 30, 2023. As of September 30, 2022, we have repurchased an aggregate 9,935,070 shares of our common stock for $395 million, at an average price of $39.74 per share, since inception of the Share Repurchase Program in May 2021.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. See Note 16 Subsequent Events for information on an increase and extension to our Share Repurchase Program.

For the three months ended September 30, 2022, we repurchased 1,921,181 shares of our common stock for $80 million at an average price of $41.78 per share. For the nine months ended September 30, 2022, we repurchased 5,845,082 shares of our common stock for $247 million at an average price of $42.29 per share. For the three months ended September 30, 2021, we repurchased 1,151,596 shares of our common stock for $39 million at an average price of $33.42 per share. For the nine months ended September 30, 2021, we repurchased 2,591,799 shares of our common stock for $84 million at an average price of $32.39 per share.

Shares repurchased were held as treasury stock as of September 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 $13 million 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 $13 million was paid on June 16, 2022. On August 3, 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 September 1, 2022 and $13 million was paid on September 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 16 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. As of September 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).

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.

We did not issue any shares of our common stock in exchange for warrants during the three months ended September 30, 2022. During the nine months ended September 30, 2022, we issued an insignificant number of shares of our common stock in exchange for warrants. During the three and nine months ended September 30, 2021, we issued 47,416 shares of common stock and received approximately $2 million related to warrants exercised.

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 provides 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.

As of September 30, 2022, 16,480 shares were issued under our ESPP.

BSP JV

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 interest on our condensed consolidated statements of operations.

NOTE 15 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 September 30,				Nine months ended September 30,
	2022		2021			2022		2021
	(in millions)
Oil	$	494	$	413		$	1,527	$	1,124
Natural gas	120		69			294		161
NGLs	66		67			205		174
Oil, natural gas and NGL sales	$	680	$	549		$	2,026	$	1,459

NOTE 16 SUBSEQUENT EVENTS

Dividends

On November 2, 2022, our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of $1.13, payable to shareholders in quarterly increments of $0.2825 per share of common stock. The actual declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. Also on November 2, 2022, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend is payable to shareholders of record at the close of business on December 1, 2022 and is expected to be paid on December 16, 2022.

Share Repurchase Program

On November 2, 2022, our Board of Directors increased the Share Repurchase Program by $200 million to $850 million and extended the program through December 31, 2023. In October 2022, we repurchased 682,792 shares of our common stock for $29 million, at an average price of $42.19 per share. As of October 31, 2022, we have repurchased an aggregate 10,617,862 shares of our common stock for $424 million, at an average price of $39.89 per share, since the inception of the Share Repurchase Program in May 2021. After giving effect to the increase, there was approximately $426 million of capacity under our Share Repurchase Program as of October 31, 2022.

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

General

We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We provide ample, affordable and reliable energy in a safe and responsible manner, to support and enhance the quality of life of Californians and the local communities in which we operate. We do this through the development of our broad portfolio of assets while adhering to our commitment to 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. We intend to pursue some or all of these projects through our Carbon TerraVault JV described below. 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 140 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 for CCS. 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 is ongoing. 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).

Carbon TerraVault Joint Venture

See Part I, Item 1 – Financial Statements, Note 8 Investments and Related Party Transactions for more information on our Carbon TerraVault JV.

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 November 2, 2022, our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of $1.13, payable to shareholders in quarterly increments of $0.2825 per share of common stock. The actual declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. Also on November 2, 2022, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend is payable to shareholders of record at the close of business on December 1, 2022 and is expected to be paid on December 16, 2022. The aggregate payment for this quarterly dividend is approximately $20 million.

Share Repurchase Program

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $650 million of our common stock through June 30, 2023. On November 2, 2022, our Board of Directors increased the Share Repurchase Program by $200 million to $850 million from $650 million and extended the program through December 31, 2023. As of October 31, 2022, we have repurchased an aggregate 10,617,862 shares of our common stock for $424 million, at an average price of $39.89 per share, since the inception of the Share Repurchase Program in May 2021. 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.

Shares repurchased are held as treasury stock. See Part I, Item 1 – Financial Statements, Note 14 Stockholders' Equity for more information on our share repurchase activity during the three and nine months ended September 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 nine months ended September 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 nine months of 2022 compared to the same period in 2021 due to 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. Currently, global oil inventories are low relative to historical levels and supply from OPEC+ and other oil producing nations are not expected to be sufficient to meet forecasted oil demand growth for the next few years. It is believed that many OPEC+ countries will be unable to increase their production levels or even produce at expected levels due to their lack of capital investments in developing incremental oil supplies over the past few years. In October 2022, OPEC+ determined to reduce production beginning in November 2022 through December 2023 by 2 million barrels per day, due to the uncertainty surrounding the global economic and oil market outlooks. 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. Brent crude oil prices have declined from the high experienced in the second quarter of 2022 and could decline further due to, among other things, a prolonged high inflationary environment, additional releases from the U.S. Strategic Petroleum Reserve or a recession. Although the forward strip prices for the next twelve months remain high relative to commodity prices in recent years, 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				Nine months ended
	September 30, 2022		June 30, 2022		September 30, 2022		September 30, 2021
Brent oil ($/Bbl)	$	97.81	$	111.79	$	102.33	$	67.78
WTI oil ($/Bbl)	$	91.56	$	108.41	$	98.09	$	64.82
NYMEX Henry Hub ($/MMBtu) Contract Month Average	$	7.85	$	6.62	$	6.22	$	3.06
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	$	8.20	$	7.17	$	6.77	$	3.18

Supply Chain and Cost Inflation

Operating and capital costs in the oil and natural gas industry are heavily influenced by commodity prices which are typically 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. Cost inflation may continue into 2023 if rising energy prices result in factory constraints, placing certain items such as directional drilling components and materials that have a high energy input intensity in short supply. 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 and could also negatively impact our results of operations and cash flows in 2023 and beyond.

Regulatory Updates

Kern County Environmental Impact Report

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 challenged the EIR and on February 25, 2020, a California Appellate Court (the 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 October 22, 2021, Kern County was ordered to cease reviewing and approving oil and gas permits until the trial court determined that the Zoning Ordinance complies with CEQA requirements. 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 verified that the noted deficiencies had been remedied and that the remedies satisfied the concerns raised by the Court. In October 2022, the trial court ruled that the Supplemental EIR was not decertified but ordered Kern County to address four discrete issues before suspension of the local permitting could be lifted, which, once resolved, would bring the Supplemental EIR into compliance with applicable laws. The four discrete issues included requirements for the removal of offsite legacy equipment to mitigate agricultural land use impacts, revising emission reduction requirements to address particulate matter, the establishment of a drinking water grant fund for disadvantaged communities in Kern County, and updating the local oil and gas ordinance to reflect these requirements. The Kern County Board of Supervisors approved these changes in August 2022. On October 12, 2022, Kern County submitted notice with the trial court of these changes and on November 2, 2022 the trial court lifted the order preventing reliance on the local permitting system. This ruling is subject to further appeal by the petitioners and there is still some potential for future disruptions to obtaining permits in Kern County until any such appeals are resolved.

Carbon Capture, Sequestration and Storage – California Program Management

On September 16, 2022, the Governor of California signed Senate Bill No. 905 into law, which contemplates the development of unitization, permitting and pipeline safety regulations over a multi-year period to facilitate the development of CCS projects in California. We believe our Carbon TerraVault projects, for which permits with the EPA have been filed, will continue to be developed on a timeline consistent with our initial expectations. These initial projects are not reliant on the unitization or permitting regulations being developed. In addition, our Carbon TerraVault projects are expected to either use emitters that are directly sited above these storage facilities or rely on pipelines for transporting CO2 that will need to comply with yet to be developed CO2 pipeline safety regulations from the federal Pipeline and Hazardous Materials Safety Administration. Delays in developing required pipeline safety regulations would delay projects requiring pipeline transportation of CO2.

The unified permitting process contemplated by Senate Bill No. 905 will be optional for project applicants and is intended to simplify the permitting process for CCS projects. In the meantime, pursuant to this legislation we are permitted to proceed with our existing and future permit applications with the EPA. This law also contemplates the implementation of a new regulatory program incorporating standards that are not yet defined and that could affect the timing of future CCS projects in California.

Senate Bill No. 905 also prohibits projects that utilize and permanently sequester CO2 in connection with EOR projects. These projects had the potential to create incremental net zero carbon oil production that displaces higher carbon intensity foreign imports. In light of this prohibition and the enhancement of energy credits under the Inflation Reduction Act of 2022 (the Act), we will transition our CalCapture project to target CCS.

We do not have any existing oil and gas production, and only have contingent resources, associated with EOR projects that rely on CO2 floods. As a result, we do not expect the limitations on EOR activities included in Senate Bill No. 905 to impact our existing oil and gas production or proved reserves.

Oil and Gas Operations – Health Protection Zones

The majority of our production is in rural areas in the San Joaquin basin and is unlikely to be affected by Senate Bill No. 1137. We are evaluating the impact on our remaining assets, including our Wilmington and Huntington Beach fields in the LA Basin and our natural gas fields in the Sacramento Basin. Certain proved undeveloped and proved developed non-producing reserves associated with projects would be impacted by this legislation; however, we may accelerate other substitute projects within the five-year period associated with our proved reserves. We do not expect this law to result in any change in our existing proved developed producing reserves or current production rates or any material change to the timing of plugging and abandonment liabilities. As a result of this law, our development plans will change but we do not currently expect an impairment of our assets or that our overall pace of development to be affected materially.

Inflation Reduction Act

President Biden signed the Inflation Reduction Act into law on August 16, 2022. Beginning in 2024, the Act’s methane emissions charge imposes a fee on excess methane emissions from certain oil and gas facilities, including some of our facilities, starting at $900 per metric ton of leaked methane in 2024 and rising to $1,200 in 2025, and $1,500 in 2026 and thereafter.

The Act also enhanced existing credits for emissions reduction and sequestration (45Q credit) by increasing the size of the credit by $35 per metric ton for permanent storage to $85 per metric ton from $50 per metric ton and extended the date for when qualifying facilities must begin construction by seven years, among other modifications. Further, a direct pay option for the 45Q credit (for a limited five-year period) was added and the Act provides an option to monetize the 45Q credit through a sale to another taxpayer. These additional energy-related tax incentives are effective for new projects beginning on January 1, 2023 and enhance the development of CCS projects in California.

Additionally, the Act includes a new corporate alternative minimum tax and an excise tax on certain repurchases of corporate stock. The new corporate alternative minimum tax provisions do not currently apply to us based on our size. The 1% stock buyback excise tax applies to certain publicly traded corporations that repurchase stock from their shareholders after December 31, 2022. The amount subject to the excise tax is the fair market value of stock repurchased by such corporation net of the fair market value of any stock issued by such corporation during such taxable year. Although the application of this excise tax is not entirely clear, any redemptions made after December 31, 2022 in connection with our Share Repurchase Program will be subject to this excise tax.

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		Nine months ended
	September 30, 2022	June 30, 2022		September 30, 2022	September 30, 2021
Oil (MBbl/d)
San Joaquin Basin	36	38		37	39
Los Angeles Basin	19	16		18	19
Ventura Basin	—	—		—	3

Total	55	54		55	61
NGLs (MBbl/d)
San Joaquin Basin	12	12		11	13



Total	12	12		11	13
Natural gas (MMcf/d)
San Joaquin Basin	131	132		128	135
Los Angeles Basin	1	1		1	1
Ventura Basin	—	—		—	5
Sacramento Basin	17	18		18	19
Total	149	151		147	160

Total Net Production (MBoe/d)	92	91		91	101

Total daily net production for the three months ended September 30, 2022, compared to the three months ended June 30, 2022 increased by approximately 1 MBoe/d, or 1%. This increase is predominately a result of our production-sharing contracts (PSCs), which positively impacted our net oil production in the three months ended September 30, 2022 by approximately 2 MBoe/d, compared to the three months ended June 30, 2022. This increase was partially offset by natural decline.

Total daily net production for the nine months ended September 30, 2022, compared to the same period in 2021, decreased by approximately 10 MBoe/d, or 10%. The decrease in production reflects the divestiture of our remaining 50% working interest in certain zones in the Lost Hills field in February 2022 and the divestiture of certain assets in our Ventura basin operations which began in the fourth quarter of 2021. Divestitures reduced our total net production by approximately 5 MBoe/d for the nine months ended September 30, 2022 compared to the prior year period. The decrease also resulted from 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 nine months ended September 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 16% of our net production for both the three and nine months ended September 30, 2022.

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
	September 30, 2022				June 30, 2022
	(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs	$	214	$	25.27	$	190	$	22.92
Excess costs attributable to PSC-type contracts	(18)		$	(2.16)	(21)		$	(2.58)
Operating costs, excluding effects of PSC-type contracts	$	196	$	23.11	$	169	$	20.34


	Nine months ended
	September 30, 2022				September 30, 2021
	(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs	$	586	$	23.71	$	523	$	19.04
Excess costs attributable to PSC-type contracts	(58)		$	(2.35)	(47)		$	(1.72)
Operating costs, excluding effects of PSC-type contracts	$	528	$	21.36	$	476	$	17.32

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		Nine months ended
	September 30, 2022	June 30, 2022	September 30, 2022	September 30, 2021
	(MBoe/d)
Total Net Production	92	91	91	101
Partners' share under PSC-type contracts	7	8	8	7
Working interest and royalty holders' share	7	8	7	9
Other	1	1	1	1
Total Gross Production	107	108	107	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
	September 30, 2022			June 30, 2022
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	97.81		$	111.79

Realized price without derivative settlements	$	97.96	100%	$	112.32	100%
Effects of derivative settlements	(35.51)			(49.15)
Realized price with derivative settlements	$	62.45	64%	$	63.17	57%

WTI	$	91.56		$	108.41

Realized price without derivative settlements	$	97.96	107%	$	112.32	104%
Realized price with derivative settlements	$	62.45	68%	$	63.17	58%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	57.68	59%	$	68.29	61%
Realized price (% of WTI)	$	57.68	63%	$	68.29	63%

Natural gas
NYMEX Henry Hub ($/MMBtu) - Contract Month Average	$	7.85		$	6.62

Realized price without derivative settlements ($/Mcf)	$	8.80	112%	$	6.85	103%
Effects of derivative settlements	(0.22)			(0.13)
Realized price with derivative settlements ($/Mcf)	$	8.58	109%	$	6.72	102%

NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	8.20		$	7.17

Realized price without derivative settlements ($/Mcf)	$	8.80	107%	$	6.85	96%
Effects of derivative settlements	(0.22)			(0.13)
Realized price with derivative settlements ($/Mcf)	$	8.58	105%	$	6.72	94%


	Nine months ended
	September 30, 2022			September 30, 2021
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	102.33		$	67.78

Realized price without derivative settlements	$	102.01	100%	$	67.62	100%
Effects of derivative settlements	(40.05)			(13.19)
Realized price with derivative settlements	$	61.96	61%	$	54.43	80%

WTI	$	98.09		$	64.82

Realized price without derivative settlements	$	102.01	104%	$	67.62	104%
Realized price with derivative settlements	$	61.96	63%	$	54.43	84%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	66.98	65%	$	49.20	73%
Realized price (% of WTI)	$	66.98	68%	$	49.20	76%

Natural gas
NYMEX Henry Hub ($/MMBtu) - Contract Month Average	$	6.22		$	3.06

Realized price without derivative settlements ($/Mcf)	$	7.33	118%	$	3.67	120%
Effects of derivative settlements	(0.12)			(0.03)
Realized price with derivative settlements ($/Mcf)	$	7.21	116%	$	3.64	119%

NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	6.77		$	3.18

Realized price without derivative settlements ($/Mcf)	$	7.33	108%	$	3.67	115%
Effects of derivative settlements	(0.12)			(0.03)
Realized price with derivative settlements ($/Mcf)	$	7.21	106%	$	3.64	114%

Oil — Brent prices decreased for the three months ended September 30, 2022 compared to the three months ended June 30, 2022 due to slowing global economic activity and ongoing releases from the U.S. Strategic Petroleum Reserve. Prices increased for the nine months ended September 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. 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 disconnects between traditional buyers and sellers of Russian-produced crude oil.

NGLs — NGL prices for the three months ended September 30, 2022 decreased compared to the three months ended June 30, 2022 as a result of incremental North American production and seasonal demand. NGL prices for the nine months ended September 30, 2022 increased compared to the nine months ended September 30, 2021 as NGL markets benefited from higher energy and fuel prices, as a whole.

Natural Gas — Our realized price for natural gas increased for the three and nine months ended September 30, 2022 as compared to the three months ended June 30, 2022 and nine months ended September 30, 2021 primarily due to strong domestic demand for power generation during the summer and the need to refill storage ahead of the upcoming heating season. Storage volumes in the beginning of 2022 were lower than the prior year, which led to increased demand to replenish inventories before the winter months.

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. Beginning in the first quarter of 2022, we 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 September 30, 2022 and June 30, 2022 and the nine months ended September 30, 2022 and 2021. Energy operating costs consist of purchased natural gas used to generate electricity for our operations and steam for our steamfloods, purchased electricity and internal costs to generate electricity used in our operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. Purchased natural gas used to generate steam in our steamfloods was reclassified from non-energy operating costs to energy operating costs beginning in the third quarter of 2022. All prior periods have been updated to conform to this presentation.


	Three months ended				Nine months ended
	September 30, 2022		June 30, 2022			September 30, 2022		September 30, 2021
	($ per Boe)
Energy operating costs	$	10.96	$	9.33		$	9.83	$	6.68
Gas processing costs	$	0.49	$	0.54		$	0.53	$	0.59
Non-energy operating costs	$	13.82	$	13.05		$	13.35	$	11.77
Operating costs	$	25.27	$	22.92		$	23.71	$	19.04


Field general and administrative expenses(a)	$	1.18	$	0.84		$	1.01	$	0.87
Field depreciation, depletion and amortization(b)	$	5.31	$	5.43		$	5.30	$	5.21
Field taxes other than on income	$	3.66	$	3.62		$	3.36	$	3.02

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 September 30, 2022 were higher than the three months ended June 30, 2022 on both a total and per Boe basis primarily as a result of higher electricity and natural gas prices (increasing energy operating costs) and downhole maintenance activity (increasing non-energy operating costs). Operating costs in the nine months ended September 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 non-energy operating costs related to repair and maintenance activities to increase during the remainder of 2022 and 2023 as inflationary pressures increase costs for services, labor and supplies.

Field taxes other than on income for the three months ended September 30, 2022 were consistent with the three months ended June 30, 2022. Field taxes other than on income for the nine months ended September 30, 2022 were also consistent with the same period in 2021, but higher on a per Boe basis due to lower production volumes in 2022. Field taxes other than income for the nine months ended September 30, 2022 compared to the same prior year period were lower for ad valorem taxes which was 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 September 30, 2022 compared to June 30, 2022

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


	Three months ended
	September 30, 2022		June 30, 2022
	(in millions)
Oil, natural gas and NGL sales	$	680	$	718
Net gain (loss) from commodity derivatives	243		(100)
Sales of purchased natural gas	113		75
Electricity sales	88		49
Other revenue	1		5
Total operating revenues	$	1,125	$	747

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $680 million for the three months ended September 30, 2022, which is a decrease of $38 million compared to $718 million for the three months ended June 30, 2022. This decrease was primarily due to lower realized prices for oil and NGLs. This decrease was partially offset by increased oil production and higher realized prices for natural gas.


	Oil		NGLs		Natural Gas		Total
	(in millions)
Three months ended June 30, 2022	$	547	$	77	$	94	$	718
Changes in realized prices	(70)		(12)		26		(56)
Changes in production	17		1		—		18
Three months ended September 30, 2022	$	494	$	66	$	120	$	680

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 $182 million for the three months ended September 30, 2022 compared to payments of $241 million for the three months ended June 30, 2022. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $21 million, or 4% compared to the three months ended June 30, 2022.

Net gain (loss) from commodity derivatives — Net gain from commodity derivatives was $243 million for the three months ended September 30, 2022 compared to a net loss of $100 million for the three months ended June 30, 2022. The change primarily resulted from non-cash changes in the fair value of our outstanding commodity derivatives 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
	September 30, 2022		June 30, 2022
	(in millions)
Non-cash commodity derivative gain	$	425	$	141


Net cash payments on settled commodity derivatives	(182)		(241)

Net gain (loss) from commodity derivatives	$	243	$	(100)

Sales of purchased natural gas — Sales of purchased natural gas relates to natural gas acquired from third parties which is subsequently sold in connection with certain of our marketing activities. Sales of purchased natural gas were $113 million for the three months ended September 30, 2022, an increase of $38 million, or 51% from $75 million during the three months ended June 30, 2022. The increase was primarily the result of higher natural gas prices. Our natural gas sales net of related purchased natural gas expense were $15 million for the three months ended September 30, 2022 compared to $8 million for the three months ended June 30, 2022.

Electricity sales — Electricity sales increased by $39 million to $88 million for the three months ended September 30, 2022 compared to $49 million for the three months ended June 30, 2022. The increase was primarily due to higher natural gas prices and demand for electricity in the summer months.

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


	Three months ended
	September 30, 2022		June 30, 2022
	(in millions)
Operating expenses
Energy operating costs	$	93	$	77
Gas processing costs	4		4
Non-energy operating costs	117		109
General and administrative expenses	59		56
Depreciation, depletion and amortization	50		50
Asset impairments	—		2
Taxes other than on income	44		42
Exploration expense	1		1
Purchased natural gas expense	98		67
Electricity generation expenses	42		33
Transportation costs	13		12
Accretion expense	10		11
Other operating expenses, net	5		9
Total operating expenses	536		473
Gain on asset divestitures	2		4
Operating income	591		278

Non-operating (expenses) income

Interest and debt expense, net	(13)		(13)

Other non-operating expenses, net	1		1
Income before income taxes	579		266
Income tax provision	(153)		(76)
Net income	$	426	$	190

Energy operating costs — Energy operating costs for the three months ended September 30, 2022 were $93 million, which was an increase of $16 million, or 21% from $77 million for the three months ended June 30, 2022. This increase was predominantly a result of higher prices for purchased natural gas, which we used to generate electricity for our operations, steam for our steamfloods and purchased electricity.

Non-energy operating costs — Non-energy operating costs for the three months ended September 30, 2022 were $117 million, which was an increase of $8 million or 7% from $109 million for the three months ended June 30, 2022. This increase was primarily a result of increased downhole maintenance activity.

Purchased natural gas expense — Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. We purchased $98 million of natural gas for marketing activities during the three months ended September 30, 2022, which was an increase of $31 million, or 46% from $67 million for the three months ended June 30, 2022. The increase was predominantly the result of higher prices in the three months ended September 30, 2022 compared to the three months ended June 30, 2022.

Income taxes – The income tax provision for the three months ended September 30, 2022 was $153 million (effective tax rate of 26%), compared to $76 million (effective tax rate of 29%) for the three months ended June 30, 2022. The effect tax rate decreased in the three months ended September 30, 2022 compared to the three months ended June 30, 2022 due to the benefit of federal tax credits.

Nine months ended September 30, 2022 compared to September 30, 2021

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


	Nine months ended September 30,
	2022		2021
	(in millions)
Oil, natural gas and NGL sales	$	2,026	$	1,459
Net loss from commodity derivatives	(419)		(603)
Sales of purchased natural gas	220		241
Electricity sales	171		131
Other revenue	27		27
Total operating revenues	$	2,025	$	1,255

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $2,026 million for the nine months ended September 30, 2022, which is an increase of $567 million compared to $1,459 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)
Nine months ended September 30, 2021	$	1,124	$	174	$	161	$	1,459
Changes in realized prices	572		63		160		795
Changes in production	(169)		(32)		(27)		(228)
Nine months ended September 30, 2022	$	1,527	$	205	$	294	$	2,026

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 $604 million for the nine months ended September 30, 2022 compared to payments of $220 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 $183 million or 15% for the nine months ended September 30, 2022 compared to the same prior-year period.

Net loss from commodity derivatives — Net loss from commodity derivatives was $419 million for the nine months ended September 30, 2022 compared to a net loss of $603 million for the same prior year period. The decrease in the net loss primarily resulted from non-cash changes in the fair value of our outstanding commodity derivatives 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:


	Nine months ended September 30,
	2022		2021
	(in millions)
Non-cash commodity derivative gain (loss)	$	185	$	(383)


Net cash payments on settled commodity derivatives	(604)		(220)

Net loss from commodity derivatives	$	(419)	$	(603)

Sales of purchased natural gas — Sales of purchased natural gas relates to natural gas acquired from third parties which is subsequently sold in connection with certain of our marketing activities. Sales of purchased natural gas were $220 million for the nine months ended September 30, 2022, a decrease of $21 million, or 9% from $241 million during the same period of 2021. The decrease was predominantly the result of lower volumes, partially offset by generally higher prices. Our natural gas sales net of related purchased natural gas expense was $34 million for the nine months ended September 30, 2022 compared to $97 million for the same period of 2021.

Electricity sales — Electricity sales increased by $40 million to $171 million for the nine months ended September 30, 2022 compared to $131 million for the same prior-year period. The increase was predominantly due to higher electricity prices associated with higher natural gas prices.

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



	Nine months ended September 30,
	2022		2021
	(in millions)
Operating expenses
Energy operating costs	$	243	$	184
Gas processing costs	13		16
Non-energy operating costs	330		323
General and administrative expenses	163		147
Depreciation, depletion and amortization	149		160
Asset impairments	2		28
Taxes other than on income	120		113
Exploration expense	3		6
Purchased natural gas expense	186		144
Electricity generation expenses	99		70
Transportation costs	37		37
Accretion expense	32		39
Other operating expenses, net	28		31
Total operating expenses	1,405		1,298
Net gain on asset divestitures	60		4
Operating income (loss)	680		(39)

Non-operating (expenses) income
Reorganization items, net	—		(5)
Interest and debt expense, net	(39)		(40)
Net loss on early extinguishment of debt	—		(2)
Other non-operating expenses, net	3		(3)
Income (loss) before income taxes	644		(89)
Income tax provision	(203)		—
Net income (loss)	$	441	$	(89)

Energy operating costs — Energy operating costs for the nine months ended September 30, 2022 were $243 million, which was an increase of $59 million, or 32% from $184 million for the same period of 2021. This increase was predominantly a result of higher prices for purchased natural gas, which we used to generate electricity for our operations, steam for our steamfloods and for purchased electricity.

Non-energy operating costs — Non-energy operating costs for the nine months ended September 30, 2022 were $330 million, which was an increase of $7 million, or 2% from $323 million for the same period of 2021. This increase was primarily a result of increased surface and downhole maintenance activity in the nine months ended September 30, 2022 compared to the same prior year period.

General and administrative expenses — General and administrative expenses increased $16 million to $163 million for the nine months ended September 30, 2022 compared to $147 million for the nine months ended September 30, 2021 as a result of increased compensation-related expenses and additional headcount related to developing our carbon management business as shown in the table below.


	Nine months ended September 30,
	2022		2021
	(in millions)
G&A – E&P, corporate and other	$	153	$	147
G&A – Carbon management business	10		—
Total general and administrative expenses	$	163	$	147

Depreciation, depletion and amortization — Depreciation, depletion and amortization decreased $11 million to $149 million for the nine months ended September 30, 2022 from $160 million for the same prior year period. The decrease was primarily the result of our divestiture of our Ventura basin assets in the fourth quarter of 2021. 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.

Asset impairments — Asset impairments were $2 million for the nine months ended September 30, 2022 compared to $28 million for the same prior year period. During the nine months ended September 30, 2022, we recorded a $2 million impairment related to the write-down of a commercial office building located in Bakersfield, California to fair market value. During the nine months ended September 30, 2021, we recorded a write-down of $25 million related to a decline in value of the same commercial office building and a $3 million write-off of capitalized costs related to projects which were abandoned. The decline in asset value of our commercial office building primarily related to limited demand for office space of this size and type in the Bakersfield market and general trends in commercial real estate due to the COVID-19 pandemic in 2021. See Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions for additional information.

Purchased natural gas expense — Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. We purchased $186 million of natural gas for marketing activities during the nine months ended September 30, 2022, which was an increase of $42 million, or 29% from $144 million for the same prior year period. The increase was predominantly the result of generally higher prices in the nine months ended September 30, 2022 compared to 2021.

Electricity generation expenses — Electricity generation expenses were $99 million for the nine months ended September 30, 2022, which is an increase of $29 million, or 41%, from $70 million in the same prior-year period. The increase was predominantly due to higher natural gas prices.

Net gain on asset divestitures – Net gain on asset divestitures for the nine months ended September 30, 2022 of $60 million primarily relates to the sale of our 50% non-operated working interest in certain horizons within our Lost Hills field and 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 nine months ended September 30, 2022 was $203 million (effective tax rate of 32%), which includes a $31 million charge for a valuation allowance recorded in the first quarter of 2022 at the time of our Lost Hills divestiture. See Part I, Item 1 – Financial Statements, Note 13 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 nine months ended September 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 September 30, 2022 were for capital investments, repurchases of our common stock and dividends.

The following table summarizes our liquidity:



	September 30, 2022
	(in millions)
Cash and cash equivalents	$	358
Revolving Credit Facility:
Borrowing capacity	602
Outstanding letters of credit	(141)
Availability	$	461

Liquidity	$	819

On October 25, 2022, the borrowing base under our Revolving Credit Facility was reaffirmed at $1.2 billion. The aggregate commitment from our lenders under our Revolving Credit Facility increased to $602 million at September 30, 2022 from $492 million at December 31, 2021 due to additional commitments from new lenders that joined this facility. See Part I, Item 1 – Financial Statements, Note 6 Debt for more information on amendments to our Revolving Credit Facility.

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) adjust our drilling program, (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 an amendment 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 September 30, 2022. See Part I, Item 1 – Financial Statements, Note 10 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of September 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 oil production and strong liquidity and maximizing our free cash flow. We entered the fourth quarter of 2022 with four drilling rigs. We plan to average three drilling rigs during the quarter in the Huntington Beach, Buena Vista, Elk Hills and Wilmington fields as we reposition for our 2023 program.

We expect our 2022 capital program to range between $380 million to $400 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 during the year for inflation and these cost increases could also impact our capital program in 2023 and beyond.

Any curtailment of the development of our properties for regulatory or operational reasons 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.

This level of expected spending is consistent with our capital allocation strategy. Following entry into the Carbon TerraVault JV with Brookfield, we anticipate that Brookfield will fund a portion of the operating cash flow that we would have otherwise provided for advancing decarbonization and other emission reducing projects. As a result, this portion of operating cash flow 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 and more details on our joint venture with Brookfield in Part I, Item 1 – Financial Statements, Note 8 Investments and Related Party Transactions.

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	Nine months ended September 30, 2022
	(in millions)
Oil and natural gas operations, corporate and other	$360 - $370	$	287
Carbon management business	20 - 30	17

Total Capital	$380 - $400	$	304

Cash Flow Analysis

Cash flows from operating activities — For the nine months ended September 30, 2022, our operating cash flow increased 26%, or $120 million, to $576 million from $456 million in the same prior period of 2021. The increases in operating cash flow for the nine months ended September 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 was partially offset by an increase in operating costs primarily related to higher prices for purchased natural gas and electricity used in our operations.

Net cash used in operating activities for the nine months ended September 30, 2022 included $21 million related to our carbon management business.

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



	Nine months ended September 30,
		2022		2021
		(in millions)
Capital investments		$	(304)	$	(128)
Changes in accrued capital investments		5		18
Proceeds from divestitures, net		79		13
Acquisitions		(17)		(53)
Distribution related to the Carbon TerraVault JV		12		—
Capitalized joint venture transaction costs		(12)		—
Other		(1)		(1)
Net cash used in investing activities		$	(238)	$	(151)

Proceeds from divestitures, net for the nine months ended September 30, 2022 included the sale of our 50% non-operated working interest in certain horizons within our Lost Hills field, certain of our Ventura basin assets and our commercial office building in Bakersfield, California. Proceeds from divestitures, net for the nine months ended September 30, 2021 included divestitures of non-core assets including unimproved land.

Net cash used in investing activities for the nine months ended September 30, 2022, included carbon management business outflows of $17 million related to acquisitions, $17 million that included permitting and easements and $9 million to replace water disposal facilities at our 26R reservoir in Elk Hills. We did not have investing activities related to our carbon management business for the nine months ended September 30, 2021.

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


	Nine months ended September 30,
		2022		2021
		(in millions)
Debt transactions, net		$	—	$	(12)

Distributions paid to a noncontrolling interest holder		—		(50)

Repurchases of common stock		(247)		(84)
Common stock dividends		(39)		—
Proceeds from warrants exercised		—		2
Issuance of common stock		1		$	—
Net cash used in financing activities		$	(285)	$	(144)

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 September 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 9 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 Policy 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) the location, drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, (ii) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (iii) the protection of health, safety and the environment, (iv) our ability to claim and utilize tax credits or other incentives, or (v) the transportation, marketing and sale of our products and CO2;

•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 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 the benefits contemplated by the business strategies and initiatives related to energy transition, including carbon capture and storage projects and other renewable energy efforts;

•our ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV;

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

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

•changes in our share repurchase program and our ability to repurchase shares under our debt agreements;

•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 our capital plan and other planned investments, stock repurchases and dividends;

•insufficient capital or lack of liquidity in the capital markets or inability to attract potential investors;

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

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

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

•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 nine months ended September 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 our PSC-type contracts. 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 September 30, 2022, we had net liabilities of $191 million for our derivative commodity positions which are carried at fair value. For more information on our derivative positions as of September 30, 2022, refer to Part I, Item 1 – Financial Statements, Note 10 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 also result in an increase to 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 September 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 September 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 September 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 September 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 September 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 9 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. Except as set forth below, there were no material changes to those risk factors during the nine months ended September 30, 2022.

New California regulations regarding setbacks are expected to reduce the value of our proved reserves.

On September 16, 2022, the Governor of California signed Senate Bill No. 1137 into law, which establishes 3,200 feet as the minimum distance between new oil and gas production wells and certain sensitive receptors such as homes, schools or parks effective January 1, 2023. This bill also imposes health, safety and environmental controls applicable to both current and new wells located within this distance of sensitive receptors related to noise, light, and dust pollution controls and air emission monitoring, as well as providing for the immediate suspension of operations at production facilities determined to not be in compliance with certain air emission requirements, among other matters. The latter provisions are effective January 1, 2025. We do not expect this bill to result in any change in our existing proved developed producing reserves or current production rates or any material change to the timing of plugging and abandonment liabilities. As a result of this bill, our development plans will change but we do not currently expect its overall pace of development to be affected materially. We will continue to monitor the effects of the new law on our operations.

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. On November 2, 2022, our Board of Directors increased the Share Repurchase Program to $850 million and extended the program through December 31, 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 September 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)
July 1, 2022 - July 31, 2022	1,122,947	$	40.00	1,122,947	$	—
August 1, 2022 - August 31, 2022	527,187	$	45.07	527,187	—
September 1, 2022 - September 30, 2022	271,047	$	42.73	271,047	—
Total	1,921,181	$	41.78	1,921,181	$	—

(a)The dollar value of shares that may yet be purchased under the Share Repurchase Program totaled $255 million as of September 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 to Registrant's Current Report on Form 8-K filed on May 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).





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:	November 7, 2022	/s/ Noelle M. Repetti
		Noelle M. Repetti
		Senior Vice President and Controller
		(Principal Accounting Officer)