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 ~~March 31,~~September 30, 2023

☐ 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 latest practicable date.

The number of shares of common stock outstanding as of ~~March 31,~~September 30, 2023 was ~~70,549,158.~~68,619,851.

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 (Loss) Income	6
	Condensed Consolidated Statements of Stockholders' Equity	67
	Condensed Consolidated Statements of Cash Flows	79
	Notes to the Condensed Consolidated Financial Statements	810
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2025
	General	2025
	~~Leadership Changes~~Reorganization	2025
	Business Environment and Industry Outlook	2025
	Regulatory Updates	2126
	Supply Chain Constraints and Inflation	26
	Production	2127
	Prices and Realizations	2329
	Statements of Operations Analysis	2431
	Liquidity and Capital Resources	2738
	Divestitures and Acquisitions	3041
	Lawsuits, Claims, Commitments and Contingencies	3041
	Critical Accounting Estimates and Significant Accounting and Disclosure Changes	3041
	Forward-Looking Statements	3142
Item 3	Quantitative and Qualitative Disclosures About Market Risk	3344
Item 4	Controls and Procedures	3344

Part II
Item 1	Legal Proceedings	3445
Item 1A	Risk Factors	3445
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	3645
Item 5	Other Disclosures	3646
Item 6	Exhibits	3747

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 natural 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.

•CDMA - Carbon Dioxide Management Agreement.

•CEQA - California Environmental Quality Act.

•CO2 - Carbon dioxide.

•DAC - Direct air capture.

•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.

•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.

•G&A - General and administrative expenses.

•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.

•MMTPA - Million metric tons per annum.

•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.

•OCTG - Oil country tubular goods.

•Oil spill prevention rate - Calculated as total Boe less net barrels lost divided by total Boe.

•OPEC - Organization of the Petroleum Exporting Countries.

•OPEC+ - OPEC together with Russia and certain other producing countries.

•PHMSA - Pipeline and Hazardous Materials Safety Administration.

•Proved developed reserves - 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.

•Scope 1 emissions - Our direct emissions.

•Scope 2 emissions - Indirect emissions from energy that we use (e.g., electricity, heat, steam, cooling) that is produced by others.

•Scope 3 emissions - Indirect emissions from upstream and downstream processing and use of our products.

•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.

•TRIR - Total Recordable Incident Rate calculated as recordable incidents per 200,000 hours for all workers (employees and contractors).

•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 ~~March 31,~~September 30, 2023 and December 31, 2022

(in millions, except share data)


		March 31,		December 31,			September 30,		December 31,
		2023		2022			2023		2022
CURRENT ASSETS	CURRENT ASSETS					CURRENT ASSETS
Cash and cash equivalents	Cash and cash equivalents	$	477	$	307	Cash and cash equivalents	$	479	$	307
Trade receivables	Trade receivables	249		326		Trade receivables	243		326
Inventories	Inventories	64		60		Inventories	71		60
Assets held for sale	Assets held for sale	13		5		Assets held for sale	13		5
Receivable from affiliate	Receivable from affiliate	30		33		Receivable from affiliate	26		33
Other current assets, net	Other current assets, net	139		133		Other current assets, net	97		133
Total current assets	Total current assets	972		864		Total current assets	929		864
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT	3,266		3,228		PROPERTY, PLANT AND EQUIPMENT	3,336		3,228
Accumulated depreciation, depletion and amortization	Accumulated depreciation, depletion and amortization	(502)		(442)		Accumulated depreciation, depletion and amortization	(614)		(442)
Total property, plant and equipment, net	Total property, plant and equipment, net	2,764		2,786		Total property, plant and equipment, net	2,722		2,786
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	14		13		INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	15		13
DEFERRED TAX ASSET		117		164
DEFERRED INCOME TAXES						DEFERRED INCOME TAXES	150		164
OTHER NONCURRENT ASSETS	OTHER NONCURRENT ASSETS	133		140		OTHER NONCURRENT ASSETS	136		140
TOTAL ASSETS	TOTAL ASSETS	$	4,000	$	3,967	TOTAL ASSETS	$	3,952	$	3,967


CURRENT LIABILITIES	CURRENT LIABILITIES					CURRENT LIABILITIES

Accounts payable	Accounts payable	260		345		Accounts payable	224		345
Liabilities associated with assets held for sale	Liabilities associated with assets held for sale	5		5		Liabilities associated with assets held for sale	5		5
Fair value of derivative contracts		154		246
Fair value of commodity derivative contracts						Fair value of commodity derivative contracts	103		246
Accrued liabilities	Accrued liabilities	298		298		Accrued liabilities	362		298

Total current liabilities	Total current liabilities	717		894		Total current liabilities	694		894
NONCURRENT LIABILITIES	NONCURRENT LIABILITIES					NONCURRENT LIABILITIES
Long-term debt, net	Long-term debt, net	592		592		Long-term debt, net	589		592

Asset retirement obligations	Asset retirement obligations	424		432		Asset retirement obligations	388		432
Other long-term liabilities	Other long-term liabilities	175		185		Other long-term liabilities	231		185

STOCKHOLDERS' EQUITY	STOCKHOLDERS' EQUITY					STOCKHOLDERS' EQUITY
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at March 31, 2023 and December 31, 2022		—		—
Common stock (200,000,000 shares authorized at $0.01 par value) (83,429,182 and 83,406,002 shares issued; 70,549,158 and 71,949,742 shares outstanding at March 31, 2023 and December 31, 2022)		1		1
Treasury stock (12,880,024 shares held at cost at March 31, 2023 and 11,456,260 shares held at cost at December 31, 2022)		(520)		(461)
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at September 30, 2023 and December 31, 2022						Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at September 30, 2023 and December 31, 2022	—		—
Common stock (200,000,000 shares authorized at $0.01 par value) (83,483,766 and 83,406,002 shares issued; 68,619,851 and 71,949,742 shares outstanding at September 30, 2023 and December 31, 2022)						Common stock (200,000,000 shares authorized at $0.01 par value) (83,483,766 and 83,406,002 shares issued; 68,619,851 and 71,949,742 shares outstanding at September 30, 2023 and December 31, 2022)	1		1
Treasury stock (14,863,915 shares held at cost at September 30, 2023 and 11,456,260 shares held at cost at December 31, 2022)						Treasury stock (14,863,915 shares held at cost at September 30, 2023 and 11,456,260 shares held at cost at December 31, 2022)	(604)		(461)
Additional paid-in capital	Additional paid-in capital	1,311		1,305		Additional paid-in capital	1,324		1,305
Retained earnings	Retained earnings	1,219		938		Retained earnings	1,253		938
Accumulated other comprehensive income	Accumulated other comprehensive income	81		81		Accumulated other comprehensive income	76		81

Total stockholders' equity	Total stockholders' equity	2,092		1,864		Total stockholders' equity	2,050		1,864
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	4,000	$	3,967	TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,952	$	3,967

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 ~~March 31,~~September 30, 2023 and 2022

(dollars in millions, except share and per share ~~data)~~data; shares in millions)


		Three months ended March 31,				Three months ended September 30,				Nine months ended September 30,
		2023		2022				2023		2022		2023		2022
REVENUES	REVENUES						REVENUES
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	715	$	628		Oil, natural gas and NGL sales	$	510	$	680	$	1,672	$	2,026
Net gain (loss) from commodity derivatives		42		(562)
Sales of purchased natural gas		184		32
Net (loss) gain from commodity derivatives							Net (loss) gain from commodity derivatives	(204)		243		(131)		(419)
Marketing of purchased natural gas							Marketing of purchased natural gas	78		113		334		220
Electricity sales	Electricity sales	68		34			Electricity sales	67		88		169		171
Other revenue	Other revenue	15		21			Other revenue	9		1		31		27
Total operating revenues	Total operating revenues	1,024		153			Total operating revenues	460		1,125		2,075		2,025

OPERATING EXPENSES	OPERATING EXPENSES						OPERATING EXPENSES
Operating costs	Operating costs	254		182			Operating costs	196		214		636		586
General and administrative expenses	General and administrative expenses	65		48			General and administrative expenses	65		59		201		163
Depreciation, depletion and amortization	Depreciation, depletion and amortization	58		49			Depreciation, depletion and amortization	56		50		170		149
Asset impairment	Asset impairment	3		—			Asset impairment	—		—		3		2
Taxes other than on income	Taxes other than on income	42		34			Taxes other than on income	48		44		132		120
Exploration expense	Exploration expense	1		1			Exploration expense	—		1		2		3
Purchased natural gas expense		124		21
Purchased natural gas marketing expense							Purchased natural gas marketing expense	31		98		182		186
Electricity generation expenses	Electricity generation expenses	49		24			Electricity generation expenses	23		42		85		99
Transportation costs	Transportation costs	17		12			Transportation costs	16		13		49		37
Accretion expense	Accretion expense	12		11			Accretion expense	12		10		35		32
Other operating expenses, net	Other operating expenses, net	13		14			Other operating expenses, net	28		5		62		28
Total operating expenses	Total operating expenses	638		396			Total operating expenses	475		536		1,557		1,405
Net gain on asset divestitures	Net gain on asset divestitures	7		54			Net gain on asset divestitures	—		2		7		60

OPERATING INCOME (LOSS)		393		(189)
OPERATING (LOSS) INCOME							OPERATING (LOSS) INCOME	(15)		591		525		680

NON-OPERATING (EXPENSES) INCOME	NON-OPERATING (EXPENSES) INCOME						NON-OPERATING (EXPENSES) INCOME

Interest and debt expense	Interest and debt expense	(14)		(13)			Interest and debt expense	(15)		(13)		(43)		(39)

Loss from investment in unconsolidated subsidiary	Loss from investment in unconsolidated subsidiary	(2)		—			Loss from investment in unconsolidated subsidiary	(3)		—		(6)		—
Other non-operating (expense) income		(1)		1
INCOME (LOSS) BEFORE INCOME TAXES		376		(201)
Income tax (provision) benefit		(75)		26
NET INCOME (LOSS)		$	301	$	(175)
Other non-operating income							Other non-operating income	3		1		5		3
(LOSS) INCOME BEFORE INCOME TAXES							(LOSS) INCOME BEFORE INCOME TAXES	(30)		579		481		644
Income tax benefit (provision)							Income tax benefit (provision)	8		(153)		(105)		(203)
NET (LOSS) INCOME							NET (LOSS) INCOME	$	(22)	$	426	$	376	$	441

Net income (loss) per share
Net (loss) income per share							Net (loss) income per share
Basic	Basic	$	4.22	$	(2.23)		Basic	$	(0.32)	$	5.75	$	5.38	$	5.77
Diluted	Diluted	$	4.09	$	(2.23)		Diluted	$	(0.32)	$	5.58	$	5.18	$	5.62

Weighted-average common shares outstanding	Weighted-average common shares outstanding						Weighted-average common shares outstanding
Basic	Basic	71.3		78.5			Basic	68.7		74.1		69.9		76.4
Diluted	Diluted	73.5		78.5			Diluted	68.7		76.3		72.6		78.5

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of ~~Stockholders' Equity~~Comprehensive (Loss) Income

For the three and nine months ended ~~March 31,~~September 30, 2023 and 2022

(in millions)

Three months ended March 31, 2023
Common Stock Treasury Stock Additional Paid-in Capital Retained Earnings Accumulated Other
Comprehensive
Income Total
Equity
Balance, December 31, 2022 $ 1 $ (461) $ 1,305 $ 938 $ 81 $ 1,864
Net income — — — 301 — 301
Share-based compensation — — 7 — — 7
Repurchases of common stock — (59) — — — (59)
Cash dividend ($0.2825 per share) — — — (20) — (20)
Shares cancelled for taxes — — (1) — — (1)
Balance, March 31, 2023 $ 1 $ (520) $ 1,311 $ 1,219 $ 81 $ 2,092


	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
Net (loss) income	$	(22)	$	426	$	376	$	441
Other comprehensive income:
Amortization of prior service cost credit included in net periodic benefit cost, net of tax(a)	(5)		—		(5)		—
Comprehensive (loss) income attributable to common stock	$	(27)	$	426	$	371	$	441

Three months ended March 31, 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 loss — — — (175) — (175)
Share-based compensation — — 5 — — 5
Repurchases of common stock — (71) — — — (71)
Cash dividend ($0.17 per share) — — — (14) — (14)
Balance, March 31, 2022 $ 1 $ (219) $ 1,293 $ 286 $ 72 $ 1,433

(a) Amortization of prior service cost credit is net of $2 million in tax for the three and nine months ended September 30, 2023.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of ~~Cash Flows~~Stockholders' Equity

For the three and ninemonths ended ~~March 31,~~September 30, 2023 ~~and 2022~~

(in millions)

Three months ended March 31,
2023 2022
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss) $ 301 $ (175)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 58 49
Deferred income tax provision (benefit) 47 (33)
Asset impairment 3 —
Net (gain) loss from commodity derivatives (42) 562
Net payments on settled commodity derivatives (65) (181)
Net gain on asset divestitures (7) (54)
Other non-cash charges to income, net 21 8
Changes in operating assets and liabilities, net (6) (16)
Net cash provided by operating activities 310 160
CASH FLOW FROM INVESTING ACTIVITIES
Capital investments (47) (99)
Changes in accrued capital investments (13) 3
Proceeds from asset divestitures, net — 60
Acquisitions — (17)
Other (1) —
Net cash used in investing activities (61) (53)
CASH FLOW FROM FINANCING ACTIVITIES
Repurchases of common stock (59) (71)
Common stock dividends (20) (13)
Issuance of common stock 1 —
Shares cancelled for taxes (1) —
Net cash used in financing activities (79) (84)
Increase in cash and cash equivalents 170 23
Cash and cash equivalents—beginning of period 307 305
Cash and cash equivalents—end of period $ 477 $ 328


	Three months ended September 30, 2023
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, June 30, 2023	$	1	$	(584)	$	1,317	$	1,295	$	81	$	2,110
Net loss	—		—		—		(22)		—		(22)

Share-based compensation	—		—		8		—		—		8



Repurchases of common stock	—		(20)		—		—		—		(20)

Cash dividend ($0.2825 per share)	—		—		—		(20)		—		(20)
Shares cancelled for taxes	—		—		(1)		—		—		(1)
Other comprehensive income, net of tax	—		—		—		—		(5)		(5)
Balance, September 30, 2023	$	1	$	(604)	$	1,324	$	1,253	$	76	$	2,050


	Nine months ended September 30, 2023
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, December 31, 2022	$	1	$	(461)	$	1,305	$	938	$	81	$	1,864
Net income	—		—		—		376		—		376



Share-based compensation	—		—		22		—		—		22


Repurchases of common stock	—		(143)		—		—		—		(143)


Cash dividend ($0.2825 per share)	—		—		—		(61)		—		(61)
Shares cancelled for taxes					(3)		—		—		(3)
Other comprehensive income, net of tax	—		—		—		—		(5)		(5)
Balance, September 30, 2023	$	1	$	(604)	$	1,324	$	1,253	$	76	$	2,050

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 ninemonths 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 dividend ($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 Cash Flows

For the three and nine months ended September 30, 2023 and 2022

(in millions)


	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
CASH FLOW FROM OPERATING ACTIVITIES
Net (loss) income	$	(22)	$	426	$	376	$	441
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	56		50		170		149
Deferred income tax (benefit) provision	(40)		137		16		166
Asset impairment	—		—		3		2
Net loss (gain) from commodity derivatives	204		(243)		131		419
Net payments on settled commodity derivatives	(95)		(182)		(223)		(604)


Net gain on asset divestitures	—		(2)		(7)		(60)



Other non-cash charges to income, net	26		15		77		42
Changes in operating assets and liabilities, net	(25)		34		(21)		21
Net cash provided by operating activities	104		235		522		576

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(33)		(107)		(119)		(304)
Changes in accrued capital investments	5		(4)		(10)		5
Proceeds from asset divestitures, net	—		3		—		79
Acquisitions	—		—		(1)		(17)
Distribution related to the Carbon TerraVault JV	—		12		—		12
Capitalized joint venture transaction costs	—		(12)		—		(12)
Other, net	—		(1)		(3)		(1)
Net cash used in investing activities	(28)		(109)		(133)		(238)

CASH FLOW FROM FINANCING ACTIVITIES












Repurchases of common stock	(20)		(80)		(143)		(247)
Common stock dividends	(19)		(13)		(59)		(39)




Issuance of common stock	—		1		1		1
Debt amendment costs	—		—		(8)		—
Shares cancelled for taxes	(1)		—		(3)		—
Debt repurchases	(5)		—		(5)		—
Net cash used in financing activities	(45)		(92)		(217)		(285)
Increase in cash and cash equivalents	31		34		172		53
Cash and cash equivalents—beginning of period	448		324		307		305
Cash and cash equivalents—end of period	$	479	$	358	$	479	$	358

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

~~March 31,~~September 30, 2023

NOTE 1 BASIS OF PRESENTATION

We are an independent energy and carbon management company committed to energy transition. We produce some of the lowest carbon intensity oil in the United States according to a joint report by Ceres and the Clean Air Task Force. We are focused on maximizing the value of our land, minerals and technical resources for oil and gas extraction and decarbonization efforts. We are in the early stages of developing several carbon capture and storage (CCS) projects ~~in California~~ and other emissions reducing ~~projects.~~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 Investment in Unconsolidated Subsidiary 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. In applying the equity method of accounting, ~~for variable interest entities that we do not control, the~~our investment isin an unconsolidated subsidiary (Carbon TerraVault JV HoldCo, LLC) was initially recognized at cost and then adjusted for our proportionate share of income or loss in addition to contributions and distributions.

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, 2022 (2022 Annual Report).

The carrying amounts of cash, cash equivalents and on-balance sheet financial instruments, other than debt, approximate fair value. Refer to Note 3 Debt for the fair value of our debt.

810

NOTE 2 INVESTMENT IN UNCONSOLIDATED SUBSIDIARY AND RELATED PARTY TRANSACTIONS

In August 2022, our wholly-owned subsidiary Carbon TerraVault I, LLC entered into a joint venture with Brookfield for the further 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;~~variable interest entity (VIE); however, we share decision-making power with Brookfield on all 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. Transactions between us and the Carbon TerraVault JV are related party transactions.

Brookfield has committed an initial $500 million to invest in CCS projects that are jointly approved through the Carbon TerraVault JV. 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 in 2022. This amount may, at our sole discretion, be distributed to us or used to satisfy future capital contributions, among other items. During 2022, $12 million 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. During 2023, $2we used approximately $7 million ~~was used~~ to satisfy a capital call. The remaining amount of the initial contribution by Brookfield which is available to us was reported as a receivable from affiliate on our condensed consolidated balance sheet. Because the parties have certain put and call rights (repurchase features) with respect to the 26R reservoir if certain milestones are not met, the initial investment by Brookfield is reflected as a contingent liability included in other long-term liabilities on our condensed consolidated ~~balance.~~balance sheets.

We entered into a Management Services Agreement (MSA) with the Carbon TerraVault JV whereby we provide administrative, operational and commercial services under a cost-plus arrangement. Services may be supplemented by using third parties and payments to us under the MSA are limited to the amount in an approved budget. The MSA may be terminated by mutual agreement of the parties, among other events.

The tables below present the summarized financial information related to our equity method investment and related party transactions for the periods presented.


		March 31,		December 31,			September 30,		December 31,
		2023		2022			2023		2022
		(in millions)					(in millions)
Investment in unconsolidated subsidiary(a)	Investment in unconsolidated subsidiary(a)	$	14	$	13	Investment in unconsolidated subsidiary(a)	$	15	$	13
Receivable from affiliate(b)	Receivable from affiliate(b)	$	30	$	33	Receivable from affiliate(b)	$	26	$	33
Property, plant and equipment(c)	Property, plant and equipment(c)	$	1	$	—	Property, plant and equipment(c)	$	4	$	—
Contingent liability related to Carbon TerraVault JV put and call rights(d)		$	49	$	48
Other long-term liabilities - Contingent liability (related to Carbon TerraVault JV put and call rights)(d)						Other long-term liabilities - Contingent liability (related to Carbon TerraVault JV put and call rights)(d)	$	51	$	48

(a)Reflects our investment less losses allocated to us of $2$6 million and $1 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2023 and the year ended December 31, 2022, respectively.

(b)At ~~March 31,~~September 30, 2023, the amount of ~~$30~~$26 million includes ~~$29~~$25 million ~~which may be distributed~~remaining of Brookfield's initial contribution available to us ~~or used to satisfy future capital calls~~ and $1 million related to the MSA and vendor reimbursements. At December 31, 2022, the amount of $33 million includes $32 million ~~which may be distributed~~remaining of Brookfield's initial contribution available to us ~~or used to satisfy future capital calls~~ and $1 million related to the MSA and vendor reimbursements.

(c)This amount includes the reimbursement to us for plugging and abandonment activities at the 26R reservoir.

(d)These amounts were included in other long-term liabilities on our condensed consolidated balance sheet. Our obligation due to repurchase features related to the 26R reservoir includes $3$5 million and $2 million of accrued interest at ~~March 31,~~September 30, 2023 and December 31, 2022, ~~respectively, that we would be required to pay should Brookfield exercise its put right.~~respectively.


		Three months ended March 31,					Three months ended September 30,				Nine months ended September 30,
		2023		2022			2023		2022		2023		2022
		(in millions)					(in millions)				(in millions)
Loss from investment in unconsolidated subsidiary	Loss from investment in unconsolidated subsidiary	$	(2)	$	—	Loss from investment in unconsolidated subsidiary	$	3	$	—	$	6	$	—
General and administrative expense(a)		$	1	$	—
General and administrative expenses(a)						General and administrative expenses(a)	$	2	$	—	$	5	$	—

(a)~~Includes amounts recognized~~General and administrative expenses on our condensed consolidated statement of operations are net of this amount invoiced by us under the MSA for ~~administrative,~~back-office operational and commercial services.

911

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).

NOTE 3 DEBT

As of ~~March 31,~~September 30, 2023 and December 31, 2022, our long-term debt consisted of the following:


		March 31,		December 31,					September 30,		December 31,
		2023		2022		Interest Rate	Maturity		2023		2022		Interest Rate	Maturity
		(in millions)							(in millions)

Revolving Credit Facility	Revolving Credit Facility	$	—	$	—	SOFR plus 3%-4% ABR plus 2%-3%	April 29, 2024	Revolving Credit Facility	$	—	$	—	SOFR plus 2.50%-3.50% ABR plus 1.50%-2.50%(a)	July 31, 2027(b)

Senior Notes	Senior Notes	600		600		7.125%	February 1, 2026	Senior Notes	595		600		7.125%	February 1, 2026
Principal amount	Principal amount	$	600	$	600			Principal amount	$	595	$	600
Unamortized debt issuance costs	Unamortized debt issuance costs	(8)		(8)				Unamortized debt issuance costs	(6)		(8)
Long-term debt, net	Long-term debt, net	$	592	$	592			Long-term debt, net	$	589	$	592

(a)At our election, borrowings under the amended Revolving Credit Facility may be alternate base rate (ABR) loans or term SOFR loans, plus an applicable margin. ABR loans bear interest at a rate 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%. Term SOFR loans bear interest at term SOFR, plus an additional 10 basis points per annum credit spread adjustment.The applicable margin is adjusted based on the commitment utilization percentage and will vary from (i) in the case of ABR loans, 1.50% to 2.50% and (ii) in the case of term SOFR loans, 2.50% to 3.50%.

(b)The Revolving Credit Facility is subject to a springing maturity to August 4, 2025 if any of our Senior Notes are outstanding on that date.

On ~~October 27, 2020,~~April 26, 2023, we entered into aan Amended and Restated Credit Agreement (Revolving Credit Facility) with Citibank, N.A., as administrative agent, and certain other ~~lenders.~~lenders, which amended and restated in its entirety the prior credit agreement dated October 27, 2020. As of ~~March 31,~~September 30, 2023, ~~this credit agreement~~our Revolving Credit Facility consisted of a senior revolving loan facility ~~(Revolving Credit Facility)~~ with an aggregate commitment of ~~$602~~$627 million. Our Revolving Credit Facility also included a sub-limit of ~~$200~~$250 million for the issuance of letters of ~~credit as~~credit. As of ~~March 31, 2023. Letters~~September 30, 2023, $148 million letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

The amendments to our Revolving Credit Facility included, among other things:

•extended the maturity date to July 31, 2027;

•increased our ability to make certain restricted payments (such as dividends and share repurchases) and certain investments (including in our carbon management business);

•released liens on certain assets securing the loans made under the Revolving Credit Facility, including our Elk Hills power plant;

•permitted us to designate the entities that hold certain of our assets, including our Elk Hills power plant, as unrestricted subsidiaries subject to meeting certain conditions;

•extended the period for which we can enter into hedges on our production from 48 months to 60 months; and

•increased our capacity to issue letters of credit from $200 million to $250 million.

We also amended the interest rates and fees we pay under our Revolving Credit Facility. Interest is payable quarterly for ABR loans and at the end of the applicable interest period for term SOFR loans, but not less than quarterly. We also pay a commitment fee on unused capacity ranging from 37.5 to 50 basis points per annum, depending on the percentage of the commitment utilized.

On October 30, 2023, we further amended our Revolving Credit Facility. See Note 13 Subsequent Events for additional information regarding this amendment.

The borrowing base is redetermined semi-annually and was reaffirmed at $1.2 billion on ~~April 26,~~October 30, 2023. 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.

At ~~March 31,~~September 30, 2023, we were in compliance with all financial and other debt covenants under our Revolving Credit Facility and Senior Notes. For more information on our Senior Notes, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2022 Annual Report.

Repurchases

In the three and nine months ended September 30, 2023, we repurchased $5 million in face value of our Senior Notes at par resulting in an insignificant extinguishment loss for the write-off of unamortized debt issuance costs. See Note 1413 Subsequent Events for additional information ~~regarding a recent amendment to our Revolving Credit Facility.~~on debt repurchases.

Fair Value

The ~~estimated~~ fair value of our fixed-rate debt at ~~March 31,~~September 30, 2023 and December 31, 2022 was approximately ~~$607~~$598 million and $574 million, respectively. We estimate fair value based on known prices ~~known~~ from market transactions (using Level 1 inputs on the fair value hierarchy).

NOTE 4 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 ~~March 31,~~September 30, 2023 and December 31, 2022 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. Upon execution of a cost sharing agreement with former lessees, we will share in on-going maintenance costs during the pendency of the challenge to the BSEE order and have recognized a liability of $12 million included in accrued liabilities at September 30, 2023.

NOTE 5 DERIVATIVES

We maintain a commodity hedging program primarily focused on crude oil, and to a lesser extent natural gas, to help protect our cash flows ~~margins and capital program~~ from the volatility of commodity ~~prices.~~prices and to optimize margins for our marketing and trading activities. We did not have any derivative instruments designated as accounting hedges as of and for the three and nine months ended ~~March 31,~~September 30, 2023 and 2022. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to ~~achieve~~implement our hedging ~~requirements and program goals.~~strategy.

~~From time to time, we may enter into derivative contracts on natural gas to either protect our cash flows from commodity price movements or optimize margins for our marketing and trading activities.~~

Summary of open derivative contracts on oil — We held the following Brent-based ~~crude oil~~ contracts as of ~~March 31,~~September 30, 2023:


		Q2 2023		Q3 2023		Q4 2023		1H 2024		2H 2024			Q4 2023		Q1 2024		Q2 2024		Q3 2024		Q4 2024		2025
Sold Calls	Sold Calls											Sold Calls
Barrels per day	Barrels per day	17,837		17,363		5,747		2,000		4,000		Barrels per day	5,747		23,650		30,000		30,000		29,000		19,748
Weighted-average price per barrel	Weighted-average price per barrel	$	60.00	$	57.06	$	57.06	$	90.53	$	90.53	Weighted-average price per barrel	$	57.06	$	90.00	$	90.07	$	90.07	$	90.07	$	85.63

Swaps	Swaps											Swaps
Barrels per day	Barrels per day	19,475		17,697		27,094		3,500		1,000		Barrels per day	27,094		9,000		7,750		7,750		5,500		3,374
Weighted-average price per barrel	Weighted-average price per barrel	$	70.48	$	69.27	$	70.73	$	78.79	$	77.20	Weighted-average price per barrel	$	70.73	$	79.37	$	79.65	$	79.64	$	77.45	$	72.66

Net Purchased Puts(a)	Net Purchased Puts(a)											Net Purchased Puts(a)
Barrels per day	Barrels per day	17,837		17,363		5,747		5,467		4,000		Barrels per day	5,747		30,584		30,000		30,000		29,000		19,748
Weighted-average price per barrel	Weighted-average price per barrel	$	76.25	$	76.25	$	76.25	$	71.80	$	66.25	Weighted-average price per barrel	$	76.25	$	67.27	$	65.17	$	65.17	$	65.17	$	60.00

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

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.

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 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 ~~March 31,~~September 30, 2023 and December 31, 2022:

March 31, 2023
Classification Gross Amounts at Fair Value Netting Net Fair Value
Assets (in millions)
Other current assets - Fair value of derivative contracts $ 48 $ (8) $ 40
Other noncurrent assets - Fair value of derivative contracts 10 (7) 3
Liabilities
Current - Fair value of derivative contracts(a)
(162) 8 (154)
Noncurrent - Fair value of derivative contracts (7) 7 —
$ (111) $ — $ (111)


September 30, 2023
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
	(in millions)
Other current assets, net	$	19	$	(17)	$	2
Other noncurrent assets	44		(44)		—

Current liabilities	(120)		17		(103)
Noncurrent liabilities	(81)		44		(37)
	$	(138)	$	—	$	(138)


December 31, 2022
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
	(in millions)
Other current assets, net(a)	$	51	$	(12)	$	39
Other noncurrent assets	7		—		7

Current liabilities(a)	(258)		12		(246)

	$	(200)	$	—	$	(200)

(a)In addition to our Brent based derivative contracts we held swaps as of March 31, 2023 for offsetting notional volumes of natural gas to secure a margin for future physical sales of natural gas related to our marketing and trading activities. The fair value of these natural gas hedges was $15 million included in ~~current liabilities at March 31, 2023.~~

December 31, 2022
Classification Gross Amounts at Fair Value Netting Net Fair Value
Assets (in millions)
Other current assets - Fair value of derivative contracts $ 51 $ (12) $ 39
Other noncurrent assets - Fair value of derivative contracts 7 — 7
Liabilities
Current - Fair value of derivative contracts(a)
(258) 12 (246)
Noncurrent - Fair value of derivative contracts — — —
$ (200) $ — $ (200)

~~(a)In addition to our Brent based derivative contracts,~~the table above, we held swaps as of December 31, 2022 for ~~offsetting notional volumes of~~ natural gas to secure a margin for future physical sales of natural gas related to our marketing and trading activities. The fair value of these natural gas hedges was $4 million included in current liabilities at December 31, 2022. There were no natural gas hedges at September 30, 2023.

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 gain (loss) from commodity derivatives on our condensed consolidated statements of operations for the three and nine months ended ~~March 31,~~September 30, 2023 and 2022. 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 6 INCOME TAXES

The following table ~~present~~presents the components of our total income tax ~~provision and a reconciliation of the U.S. federal statutory rate to our effective tax rate:~~provision:

Three months ended March 31,
2023 2022
(in millions)
Net income (loss) before income taxes $ 376 $ (201)
Current income tax provision 28 7
Deferred income tax provision (benefit) 47 (33)
Total income tax provision (benefit) $ 75 $ (26)


	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
(Loss) income before income taxes	$	(30)	$	579	$	481	$	644

Current income tax provision	32		16		89		37
Deferred income tax (benefit) provision	(40)		137		16		166
Total income tax (benefit) provision	$	(8)	$	153	$	105	$	203

Three months ended March 31,
2023 2022
U.S. federal statutory tax rate 21 % 21 %
State income taxes, net 7 7
Change in the valuation allowance (8) (15)
Effective tax rate 20 % 13 %

InDuring the ~~first quarter of~~nine months ended September 30, 2022, we recognized a valuation allowance of $35 million for a portion of the tax loss on the sale of our Lost Hills assets, the deductibility of which was limited. WeDuring the nine months ended September 30, 2023, we recognized the benefit of this tax loss ~~in the first quarter of 2023~~ by releasing the valuation allowance after we jointly agreed to amend the original tax treatment with the buyer. See Note 7 Divestitures and Acquisitions for more information on our Lost Hills transaction.

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

NOTE 7 DIVESTITURES AND ACQUISITIONS

Divestitures

Ventura Basin Transactions

In the three and nine months ended ~~March 31,~~September 30, 2022, we recorded a gain of $6$2 million and $12 million, respectively, related to the sale of certain Ventura basin assets. 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~~could occur in the ~~second half~~fourth 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 sheets at ~~March 31,~~September 30, 2023 and December 31, 2022. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions in our 2022 Annual Report for additional information on the Ventura basin transactions.

Lost Hills Transaction

During the ~~three months ended March 31,~~first quarter of 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.~~projects until January 1, 2026. We also retained 100% of the deep rights and related seismic data.

Other

During the ~~three~~nine months ended ~~March 31,~~September 30, 2023, we sold a ~~non-core~~non-producing asset in exchange for the assumption of ~~plugging and abandonment~~ liabilities recognizing a $7 million gain. During the ~~three~~nine months ended ~~March 31,~~September 30, 2022, we sold non-core assets recognizing ~~a $1 million~~an insignificant loss.

1315

Acquisitions

During the ~~three~~nine months ended ~~March 31,~~September 30, 2022, we acquired properties for carbon management activities for approximately $17 million. We ~~are evaluating the sale~~intend to divest a portion of ~~certain unwanted~~these assets ~~that were part of this acquisition~~ and recognized an impairment of $3 million in the first quarter of 2023. The fair value, ~~of these assets,~~ using Level 3 inputs in the fair value hierarchy, declined during the first quarter of 2023 due to market conditions ~~including~~(including inflation and rising interest ~~rates. These~~rates). The assets are classified as held for sale as of ~~March 31,~~September 30, 2023 on our condensed consolidated balance sheet.

NOTE 8 STOCKHOLDERS' EQUITY

Share Repurchase Program

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.1 billion of our common stock through June 30, 2024. 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. The following is a summary of our share repurchases, held as treasury stock for the periods presented:

Total Number of Shares Purchased Dollar Value of Shares Purchased Average Price Paid per Share
(number of shares) (in millions) ($ per share)
Three months ended March 31, 2022 1,668,456 $ 71 $ 42.52
Three months ended March 31, 2023 1,423,764 $ 59 $ 41.25
Inception of Program (May 2021) through March 31, 2023 12,880,024 $ 519 $ 40.31


	Total Number of Shares Purchased	Total Value of Shares Purchased		Average Price Paid per Share
	(number of shares)	(in millions)		($ per share)
Three months ended September 30, 2022	1,921,181	$	80	$	41.78
Three months ended September 30, 2023	365,145	$	20	$	54.75

Nine months ended September 30, 2022	5,845,082	$	247	$	42.29
Nine months ended September 30, 2023	3,407,655	$	143	$	41.69

Inception of Program (May 2021) through September 30, 2023	14,863,915	$	604	$	40.53

Note: The ~~dollar~~total value of shares purchased ~~does not include commissions and~~includes approximately $1 million in the nine months ended September 30, 2023 related to excise taxes on share ~~repurchases.~~repurchases, which was effective beginning in 2023. Commissions paid were not significant in all periods presented.

Dividends

~~On February 23, 2023, our~~Our Board of Directors declared ~~a quarterly~~the following cash ~~dividend~~dividends for each of ~~$0.2825 per share of common stock and amounted to $20 million in~~ the ~~aggregate. The dividend was payable to shareholders of record at the close of business on March 6, 2023 and was paid on March 16, 2023.~~periods presented.


	Total Dividend		Rate Per Share
	(in millions)		($ per share)
2023
Three months ended March 31, 2023	$	20	$	0.2825
Three months ended June 30, 2023	20		$	0.2825
Three months ended September 30, 2023	19		$	0.2825
Nine months ended September 30, 2023	$	59
2022
Three months ended March 31, 2022	$	13	$	0.1700
Three months ended June 30, 2022	13		$	0.1700
Three months ended September 30, 2022	13		$	0.1700
Nine months ended September 30, 2022	$	39

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 1413 Subsequent Events for information on future cash dividends.

Warrants

In October 2020, 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 ~~March 31,~~September 30, 2023, we had outstanding warrants exercisable into ~~4,295,321~~4,289,825 shares of our common stock (subject to adjustments pursuant to the terms of the warrants). During the three and nine months ended ~~March 31,~~September 30, 2023, we issued 1,958 and 2,179 shares of our common stock, respectively, in exchange for warrants. During the three and nine months ended September 30, 2022, we issued an insignificant ~~amount~~number of shares of our common stock in exchange for warrants.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 11 Stockholders' Equity in our 2022 Annual Report for additional information on the terms of our warrants.

NOTE 9 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) were calculated using the treasury stock method for the three and nine months ended ~~March 31,~~September 30, 2023 and 2022. 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 ~~March 31,~~September 30, 2023 and 2022:


		Three months ended March 31,					Three months ended September 30,				Nine months ended September 30,
		2023		2022					2023		2022		2023		2022
		(in millions, except per-share amounts)				(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS	Numerator for Basic and Diluted EPS							Numerator for Basic and Diluted EPS
Net income (loss)		$	301	$	(175)
Net (loss) income								Net (loss) income	$	(22)	$	426	$	376	$	441

Denominator for Basic EPS	Denominator for Basic EPS							Denominator for Basic EPS
Weighted-average shares	Weighted-average shares	71.3		78.5				Weighted-average shares	68.7		74.1		69.9		76.4

Potential Common Shares, if dilutive:	Potential Common Shares, if dilutive:							Potential Common Shares, if dilutive:
Warrants	Warrants	0.5		—				Warrants	—		0.7		0.8		0.7
Restricted Stock Units	Restricted Stock Units	0.9		—				Restricted Stock Units	—		0.8		1.0		0.7
Performance Stock Units	Performance Stock Units	0.8		—				Performance Stock Units	—		0.7		0.9		0.7

Denominator for Diluted EPS	Denominator for Diluted EPS							Denominator for Diluted EPS
Weighted-average shares	Weighted-average shares	73.5		78.5				Weighted-average shares	68.7		76.3		72.6		78.5

EPS	EPS							EPS
Basic	Basic	$	4.22	$	(2.23)			Basic	$	(0.32)	$	5.75	$	5.38	$	5.77
Diluted	Diluted	$	4.09	$	(2.23)			Diluted	$	(0.32)	$	5.58	$	5.18	$	5.62

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

Three months ended March 31,
2023 2022
(in millions)
Shares issuable upon exercise of warrants — 4.3
Shares issuable upon settlement of RSUs — 1.1
Shares issuable upon settlement of PSUs — 1.0
Total antidilutive shares — 6.4

~~NOTE 10 PENSION AND POSTRETIREMENT BENEFIT PLANS~~

~~The following table sets forth the components of the net periodic benefit costs for our defined benefit pension and postretirement benefit plans for the three months ended March 31, 2023 and 2022:~~

Three months ended March 31, Three months ended March 31,
2023 2022
Pension
Benefit Postretirement
Benefit Pension
Benefit Postretirement
Benefit
(in millions) (in millions)
Service cost - benefits earned during the period $ — $ — $ — $ 1
Amortization of prior service cost credit — (1) — (1)
Net periodic benefit costs $ — $ (1) $ — $ —

We did not make contributions to our defined benefit plans during the three months ended March 31, 2023 and do not expect to make any additional contributions during the remainder of the year. During the three months ended March 31, 2022, we made contributions of approximately $1 million to our defined benefit plans.


	Three months ended September 30,		Nine months ended September 30,
	2023	2022	2023	2022
(in millions)
Shares issuable upon exercise of warrants	4.3	—	—	—
Shares issuable upon settlement of RSUs	1.3	—	—	—
Shares issuable upon settlement of PSUs	1.6	—	—	—
Total antidilutive shares	7.2	—	—	—

~~NOTE 11 REVENUE~~

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 March 31,
2023 2022
(in millions)
Oil $ 390 $ 486
Natural gas 263 80
NGLs 62 62
Oil, natural gas and NGL sales $ 715 $ 628

NOTE 1210 SUPPLEMENTAL ACCOUNT BALANCES

Revenues — We derive most of our revenue from sales of oil, natural gas and natural gas liquids (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,
	2023		2022			2023		2022
	(in millions)
Oil	$	402	$	494		$	1,154	$	1,527
Natural gas	61		120			367		294
NGLs	47		66			151		205
Oil, natural gas and NGL sales	$	510	$	680		$	1,672	$	2,026

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:


		March 31,		December 31,			September 30,		December 31,
		2023		2022			2023		2022
		(in millions)					(in millions)
Materials and supplies	Materials and supplies	$	61	$	56	Materials and supplies	$	67	$	56
Finished goods	Finished goods	3		4		Finished goods	4		4
Inventories	Inventories	$	64	$	60	Inventories	$	71	$	60

Other current assets, net — Other current assets, net ~~includes~~include the following:


		March 31,		December 31,			September 30,		December 31,
		2023		2022			2023		2022
		(in millions)					(in millions)
Net amounts due from joint interest partners(a)	Net amounts due from joint interest partners(a)	$	39	$	39	Net amounts due from joint interest partners(a)	$	43	$	39

Fair value of derivative contracts		40		39
Fair value of commodity derivative contracts						Fair value of commodity derivative contracts	2		39
Prepaid expenses	Prepaid expenses	16		17		Prepaid expenses	16		17
Greenhouse gas allowances	Greenhouse gas allowances	19		—		Greenhouse gas allowances	14		—
Natural gas margin deposits	Natural gas margin deposits	16		16		Natural gas margin deposits	3		16
Income tax receivable	Income tax receivable	—		10		Income tax receivable	2		10
Other	Other	9		12		Other	17		12
Other current assets, net	Other current assets, net	$	139	$	133	Other current assets, net	$	97	$	133

(a)Included in the ~~March 31,~~September 30, 2023 and December 31, 2022 net amounts due from joint interest partners are allowances of $1 million.

Other noncurrent assets — Other noncurrent assets ~~includes~~include the following:


		March 31,		December 31,			September 30,		December 31,
		2023		2022			2023		2022
		(in millions)					(in millions)
Operating lease right-of-use assets	Operating lease right-of-use assets	$	68	$	73	Operating lease right-of-use assets	$	68	$	73
Deferred financing costs - Revolving Credit Facility	Deferred financing costs - Revolving Credit Facility	5		6		Deferred financing costs - Revolving Credit Facility	12		6
Emission reduction credits	Emission reduction credits	11		11		Emission reduction credits	11		11
Prepaid power plant maintenance	Prepaid power plant maintenance	29		28		Prepaid power plant maintenance	33		28
Fair value of derivative contracts		3		7
Fair value of commodity derivative contracts						Fair value of commodity derivative contracts	—		7
Deposits and other	Deposits and other	17		15		Deposits and other	12		15
Other noncurrent assets	Other noncurrent assets	$	133	$	140	Other noncurrent assets	$	136	$	140

Accrued liabilities — Accrued liabilities ~~includes~~include the following:

March 31, December 31,
2023 2022
(in millions)
Accrued employee-related costs $ 40 $ 49
Accrued taxes other than on income 38 32
Asset retirement obligations 62 59
Accrued interest 9 19
Operating lease liability 14 18
Premiums due on derivative contracts 49 58
Liability for settlement payments on derivative contracts 23 33
Amounts due under production-sharing contracts 7 —
Income taxes payable 19 1
Other 37 29
Accrued liabilities $ 298 $ 298


	September 30,		December 31,
	2023		2022
	(in millions)
Employee-related costs	$	78	$	49
Taxes other than on income	49		32
Asset retirement obligations	91		59
Interest	8		19
Operating lease liability	13		18

Premiums due on commodity derivative contracts	24		58
Liability for settlement payments on commodity derivative contracts	37		33
Amounts due under production-sharing contracts	15		—
Signal Hill maintenance	12		8


Other	35		22
Accrued liabilities	$	362	$	298

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


		March 31,		December 31,			September 30,		December 31,
		2023		2022			2023		2022
		(in millions)					(in millions)
Compensation-related liabilities	Compensation-related liabilities	$	38	$	36	Compensation-related liabilities	$	37	$	36
Postretirement and pension benefit plans		31		33
Postretirement benefit plan						Postretirement benefit plan	32		33
Operating lease liability	Operating lease liability	50		52		Operating lease liability	53		52

Premiums due on derivative contracts		—		8
Contingent liability related to Carbon TerraVault JV put and call rights		49		48
Fair value of commodity derivative contracts						Fair value of commodity derivative contracts	37		—
Premiums due on commodity derivative contracts						Premiums due on commodity derivative contracts	13		8
Contingent liability (related to Carbon TerraVault JV put and call rights)						Contingent liability (related to Carbon TerraVault JV put and call rights)	51		48
Other	Other	7		8		Other	8		8
Other long-term liabilities	Other long-term liabilities	$	175	$	185	Other long-term liabilities	$	231	$	185

General and administrative expenses — The table below shows G&A expenses for our exploration and production business ~~(in addition to~~(including unallocated corporate overhead and other) separately from our carbon management business. The amounts shown for our carbon management business are net of amounts ~~reimbursable to~~invoiced by us under the MSA ~~with~~to the Carbon TerraVault JV. See Note 2 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV.

Three months ended March 31,
2023 2022
(in millions)
Exploration and production, corporate and other $ 62 $ 47
Carbon management business 3 1
Total general and administrative expenses $ 65 $ 48


	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Exploration and production, corporate and other	$	61	$	54	$	191	$	153
Carbon management business	4		5		10		10
Total general and administrative expenses	$	65	$	59	$	201	$	163

Other operating expenses, net — The table below shows other operating expenses, net for our exploration and production business ~~(in addition to~~(including unallocated corporate overhead and other) separately from our carbon management business. Carbon management expenses ~~includes~~include lease cost for carbon sequestration easements, advocacy, and other startup related costs.

Three months ended March 31,
2023 2022
(in millions)
Exploration and production, corporate and other $ 9 $ 14
Carbon management business 4 —
Total other operating expenses, net $ 13 $ 14
In August 2023, we implemented organizational changes that resulted in a headcount reduction of 75 employees. As a result, we recognized a charge of $7 million in other operating expenses, net on the condensed consolidated statement of operations for the three months ended September 30, 2023, primarily related to severance benefits. For the nine months ended September 30, 2023, we recognized a severance charge of $10 million.


	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Exploration and production, corporate and other	$	19	$	2	$	41	$	25
Carbon management business	9		3		21		3
Total other operating expenses, net	$	28	$	5	$	62	$	28

NOTE 1311 SUPPLEMENTAL CASH FLOW INFORMATION

We ~~did not make~~paid $29 million and $80 million of U.S. federal orand state income tax payments during the three and nine months ended ~~March 31,~~September 30, 2023, orrespectively. We paid $20 million of U.S. federal income tax payments during the three and nine months ended ~~March 31,~~September 30, 2022. No state income tax payments were made in the three and nine months ended September 30, 2022.

Interest paid, net of capitalized amounts, was ~~$21 million and~~ $22 million for the three months ended ~~March 31,~~September 30, 2023 and $44 million for the nine months ended September 30, 2023. Interest paid, net of capitalized amounts, was $21 million for the three months ended September 30, 2022 and $43 million for the nine months ended September 30, 2022. Interest income was $5 million and $14 million for the three and nine months ended September 30, 2023, respectively.

Non-cash investing activities in the three and nine months ended ~~March 31,~~September 30, 2023 included $2$4 million and $7 million, respectively, related to aour share of capital ~~call for~~calls by the Carbon TerraVault JV. 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 2 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV.

Non-cash financing activities in the three and nine months ended ~~March 31,~~September 30, 2023 included ~~an insignificant amount~~$1 million and $2 million, respectively, for dividends accrued for stock-based ~~compensation awards.~~compensation. For the three and nine months ended ~~March 31,~~September 30, 2022 dividends accrued for stock-based compensation awards was $1 million. Non-cash financing activities in the ~~three~~nine months ended ~~March 31,~~September 30, 2023 also included approximately $1 million related to an excise tax on share repurchases that we expect will be paid in 2024.

NOTE 12 CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have designated certain of our subsidiaries as Unrestricted Subsidiaries under the indenture governing our Senior Notes (Senior Notes Indenture). Unrestricted Subsidiaries (as defined in the Senior Notes Indenture) are subject to fewer restrictions under the Senior Notes Indenture. We are required under the Senior Notes indenture to present the financial condition and results of operations of CRC and its Restricted Subsidiaries (as defined in the Senior Notes Indenture) separate from the financial condition and results of operations of its Unrestricted Subsidiaries. The following condensed consolidating balance sheets as of September 30, 2023 and December 31, 2022 and the condensed consolidating statements of operations for the three and nine months ended September 30, 2023 and 2022, as applicable, reflect the condensed consolidating financial information of our parent company, CRC (Parent), our combined Unrestricted Subsidiaries, our combined Restricted Subsidiaries and the elimination entries necessary to arrive at the information for the Company on a consolidated basis. The financial information may not necessarily be indicative of the financial condition and results of operations had the Unrestricted Subsidiaries operated as independent entities.

Condensed Consolidating Balance Sheets

As of September 30, 2023 and December 31, 2022


	As of September 30, 2023
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
	(in millions)
Total current assets	$	488	$	27	$	414	$	—	$	929
Total property, plant and equipment, net	13		7		2,702		—		2,722
Investments in consolidated subsidiaries	2,315		(12)		1,434		(3,737)		—
Deferred tax asset	150		—		—		—		150
Investment in unconsolidated subsidiary	—		15		—		—		15
Other assets	13		30		93		—		136
TOTAL ASSETS	$	2,979	$	67	$	4,643	$	(3,737)	$	3,952

Total current liabilities	109		8		577		—		$	694
Long-term debt	589		—		—		—		589
Asset retirement obligations	—		—		388		—		388
Other long-term liabilities	75		68		88		—		231
Amounts due to (from) affiliates	156		12		(168)		—		—
Total equity	2,050		(21)		3,758		(3,737)		2,050
TOTAL LIABILITIES AND EQUITY	$	2,979	$	67	$	4,643	$	(3,737)	$	3,952


	As of December 31, 2022
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
	(in millions)
Total current assets	$	329	$	33	$	502	$	—	$	864
Total property, plant and equipment, net	13		6		2,767		—		2,786
Investments in consolidated subsidiaries	2,096		—		1,512		(3,608)		—
Deferred tax asset	164		—		—		—		164
Investment in unconsolidated subsidiary	—		13		—		—		13
Other assets	8		33		99		—		140
TOTAL ASSETS	$	2,610	$	85	$	4,880	$	(3,608)	$	3,967

Total current liabilities	76		7		811		—		$	894
Long-term debt	592		—		—		—		592
Asset retirement obligations	—		—		432		—		432
Other long-term liabilities	78		67		40		—		185

Total equity	1,864		11		3,597		(3,608)		1,864
TOTAL LIABILITIES AND EQUITY	$	2,610	$	85	$	4,880	$	(3,608)	$	3,967

Condensed Consolidating Statement of Operations

For the three and nine months ended September 30, 2023 and 2022


	Three months ended September 30, 2023
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
	(in millions)
Total revenues	$	6	$	—	$	454	$	—	$	460
Total costs and other	66		12		397		—		475

Non-operating (loss) income	(12)		(4)		1		—		(15)
(LOSS) INCOME BEFORE INCOME TAXES	(72)		(16)		58		—		(30)
Income tax benefit	8		—		—		—		8
NET (LOSS) INCOME	$	(64)	$	(16)	$	58	$	—	$	(22)


	Three months ended September 30, 2022
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
	(in millions)
Total revenues	$	1	$	—	$	1,124	$	—	$	1,125
Total costs and other	43		14		479		—		536
Gain on asset divestitures	—		—		2		—		2
Non-operating (loss) income	(14)		—		2		—		(12)
(LOSS) INCOME BEFORE INCOME TAXES	(56)		(14)		649		—		579
Income tax provision	(153)		—		—		—		(153)
NET (LOSS) INCOME	$	(209)	$	(14)	$	649	$	—	$	426


	Nine months ended September 30, 2023
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
	(in millions)
Total revenues	$	14	$	—	$	2,061	$	—	$	2,075
Total costs and other	177		31		1,349		—		1,557
Gain on asset divestitures	—		—		7		—		7
Non-operating (loss) income	(39)		(9)		4		—		(44)
(LOSS) INCOME BEFORE INCOME TAXES	(202)		(40)		723		—		481
Income tax provision	(105)		—		—		—		(105)
NET (LOSS) INCOME	$	(307)	$	(40)	$	723	$	—	$	376


	Nine months ended September 30, 2022
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
	(in millions)
Total revenues	$	1	$	—	$	2,024	$	—	$	2,025
Total costs and other	125		21		1,259		—		1,405
Gain on asset divestitures	—		—		60		—		60
Non-operating (loss) income	(41)		—		5		—		(36)
(LOSS) INCOME BEFORE INCOME TAXES	(165)		(21)		830		—		644
Income tax provision	(203)		—		—		—		(203)
NET (LOSS) INCOME	$	(368)	$	(21)	$	830	$	—	$	441

NOTE 1413 SUBSEQUENT EVENTS

~~Amendment to our Revolving Credit Facility~~

~~On April 26, 2023, we amended our existing Revolving Credit Facility.The amended~~ Revolving Credit Facility ~~provides for an initial aggregate commitment of $592 million and a borrowing base of $1.2 billion.The amendments included, among other things:~~

•~~extending the maturity date to July 31, 2027 (subject to a springing maturity to~~ ~~August 4, 2025 if any of our Senior Notes are outstanding on that date);~~

•~~increasing our ability to make certain restricted payments (such as dividends and share repurchases) and certain investments (including in our carbon management business);~~

•~~releasing liens on certain assets securing the loans made under the Revolving Credit Facility, including our Elk Hills power plant;~~

•~~permitting us to designate the entities that hold certain of our assets, including our Elk Hills power plant, as unrestricted subsidiaries subject to meeting certain conditions;~~

•~~extending the period for which we can enter into hedges on our production from 48 months to 60 months; and~~

•~~increasing our capacity to issue letters of credit from $200 million to $250 million.~~

We also amended the interest rates and fees we pay under our Revolving Credit Facility. At our election, borrowings under the amended Revolving Credit Facility may be alternate base rate (ABR) loans or term SOFR loans, plus an applicable margin. ABR loans bear interest at a rate 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%. Term SOFR loans bear interest at term SOFR, plus an additional 10 basis points per annum credit spread adjustment.The applicable margin is adjusted based on the commitment utilization percentage and will vary from (i) in the case of ABR loans, 1.50% to 2.50% and (ii) in the case of term SOFR loans, 2.50% to 3.50%. We also pay customary fees and expenses. Interest is payable quarterly for ABR loans and at the end of the applicable interest period for term SOFR loans, but not less than quarterly. We also pay a commitment fee on unused capacity ranging from 37.5 to 50 basis points per annum, depending on the percentage of the commitment utilized.

~~Dividends~~Amendment

On ~~April 28,~~October 30, 2023 we amended our Revolving Credit Facility to increase our flexibility to incur new indebtedness in the form of term loans. In addition, the aggregate commitment amount of the Revolving Credit Facility was increased by $3 million to $630 million.

Dividend

On November 1, 2023, our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of $1.24, payable to shareholders in quarterly increments of $0.31 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 1, 2023, our Board of Directors declared a quarterly cash dividend of ~~$0.2825~~$0.31 per share of common stock. The dividend is payable to shareholders of record at the close of business on ~~June~~December 1, 2023 and is expected to be paid on ~~June 16,~~December 15, 2023.

Debt Repurchases

In October 2023, we repurchased $30 million in face value of our Senior Notes. After the write-off of a portion of the unamortized debt issuance costs, the extinguishment loss was insignificant.

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

General

We are an independent energy and carbon management company committed to energy transition. We produce some of the lowest carbon intensity oil in the United States according to a joint report by Ceres and the Clean Air Task ~~Force and~~Force. We are focused on maximizing the value of our land, minerals and technical resources for oil and gas extraction and decarbonization efforts. We are in the early stages of developing several carbon capture and storage (CCS) projects ~~in California~~ and other emissions reducing ~~projects.~~projects in California. We intend to pursue some or all of these projects through our Carbon TerraVault JV that we formed with BGTF Sierra Aggregator LLC (Brookfield). 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 carbon management. 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, 2022 (2022 Annual Report) and for more information on the Carbon TerraVault JV, see Part I, Item 1 – Financial Statements, Note 2 Investment in Unconsolidated Subsidiary and Related Party Transactions.

~~Leadership Changes~~Reorganization

~~On February 24,~~In August 2023, we ~~announced~~implemented organizational changes that ~~Francisco J. Leon,~~resulted in a headcount reduction of 75 employees. These actions were taken to better align our ~~current Executive Vice President~~resources to our strategic priorities and ~~Chief Financial Officer, will succeed Mark A. (Mac) McFarland as~~improve our ~~President~~operational efficiency. As a result, we recognized a charge of $7 million in other operating expenses, net for the three months ended September 30, 2023, primarily related to severance benefits. For the nine months ended September 30, 2023, we recognized a severance charge of $10 million. We expect these actions, along with other initiatives taken to streamline our operations, to result in at least $55 million of savings in operating and Chief Executive Officer, and joined our Board of Directors. Mr. McFarland will continue to serve as a non-executive member of our Board of Directors and Chair of the Board of our Carbon TerraVault subsidiary. Manuela (Nelly) Molina has been appointed Executive Vice President and Chief Financial Officer, effective May 8, 2023.overhead costs on an annualized basis.

Business Environment and Industry Outlook

Commodity Prices

Our operating results and those of the oil and natural 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 may 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 declined in the three months ended March 31, 2023 compared~~ Refer to the three months ended December 31, 2022 due to economic uncertainty and recession concerns amid the banking crisis. Natural gas index prices decreased in the three months ended March 31, 2023 compared to the three months ended December 31, 2022 as a result of generally warmer-than-normal weather across most of North America, the slow pace of storage draw-downs and increased natural gas production in the United States. However, local natural gas prices in California experienced significant volatility resulting in an increase in our average realized prices between these periods as discussed below in Prices and Realizations.below for information on our realized prices.

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


		Three months ended				Three months ended				Nine months ended
		March 31, 2023		December 31, 2022				September 30, 2023		June 30, 2023		September 30, 2023		September 30, 2022
Brent oil ($/Bbl)	Brent oil ($/Bbl)	$	82.22	$	88.60		Brent oil ($/Bbl)	$	85.95	$	78.01	$	82.06	$	102.33
WTI oil ($/Bbl)	WTI oil ($/Bbl)	$	76.13	$	82.64		WTI oil ($/Bbl)	$	82.26	$	73.78	$	77.39	$	98.09
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	$	3.42	$	6.26		NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	$	2.55	$	2.10	$	2.69	$	6.77

2025

Regulatory Updates

CalGEM is California's primary regulator of the oil and natural gas production industry on private and state lands, with additional oversight from the State Lands Commission’s administration of state surface and mineral interests. From time to time we have experienced significant delays with respect to obtaining drilling permits from CalGEM for our operations. A variety of factors outside of our control can lead to such delays. CalGEM has not issued any permits for new production wells to any operators since December 2022. However, other than in the Wilmington Field as described below, CalGEM is generally issuing permits for workovers and plugging and abandonment throughout California, including Kern County.Water Injection

~~Commencing in February 2023, CalGEM began returning our applications for permits~~Our operations in the Wilmington Oil Field ~~including permits for new production~~utilize injection wells ~~workovers~~to reinject produced water pursuant to waterflooding plans. These operations are subject to regulation by the City of Long Beach and ~~plugging and abandonment operations. CalGEM cited concerns regarding the adequacy of the related environmental impact report for purposes of meeting CEQA requirements.~~CalGEM. We are ~~working together~~currently in discussions with the City of Long Beach and CalGEM with respect to ~~address~~what injection well pressure gradient complies with CalGEM’s ~~concerns regarding conducting future re-drills, workover~~regulatory requirements for the protection of underground sources of drinking water, while at the same time mitigating subsidence risk. CalGEM's local office has preliminarily indicated that the injection well pressure gradient should be reduced from the gradient that has been used for several decades, although a final determination has not yet been made and ~~plugging~~remains subject to our ongoing discussions. If CalGEM were to ultimately determine to reduce the injection well pressure gradient, and ~~abandonment activities. Barring~~we were unable to reverse that decision on appeal or other legal challenge, we expect any ~~additional or subsequent changes~~material reduction in injection well pressure gradient for our ~~issued permits from CalGEM, our existing permit inventory will allow us to execute our previously announced capital program~~operations in the Wilmington Oil Field ~~for 2023.~~would result in a decrease in production and reserves from the field. For additional information, see Part I, Item 1 & 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities and the Risk factor entitled "Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans" in our 2022 Annual Report.

Bonding Requirements and AB 1167

See Part II, Item 1A – Risk Factors for recent California legislative activity on bonding requirements associated with certain transfers of interests in oil and gas wells.

California Climate Disclosures

In October 2023, the Governor of California signed two bills that will require climate-related disclosures, both of which apply to us. Senate Bill 253 (SB-253) requires the annual disclosure of Scope 1, Scope 2 and Scope 3 GHG emissions, with certain GHG emissions data subject to third-party assurance. The bill requires disclosure beginning in 2026 (for the 2025 reporting year). Senate Bill 261 (SB-261) requires biennial disclosures posted on a company's website related to climate-related financial risks and the measures a company has adopted to reduce and adapt to such risks.

Supply Chain Constraints and Inflation

We continued to experience relatively flat pricing from our suppliers in the nine months ended September 30, 2023 compared to the same period in 2022. We have long term vendor relationships and have taken measures to limit the effects of inflation by entering into contracts for a significant majority of our materials and services with terms of one to three years. We have not experienced any meaningful inflation in connection with recent contract renewals and continue to expect minimal inflation in our supply chain.

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.


		Three months ended		Three months ended		Nine months ended
		March 31, 2023	December 31, 2022			September 30, 2023	June 30, 2023	September 30, 2023	September 30, 2022
Oil (MBbl/d)	Oil (MBbl/d)				Oil (MBbl/d)
San Joaquin Basin	San Joaquin Basin	35	36		San Joaquin Basin	33	34	34	37
Los Angeles Basin	Los Angeles Basin	20	19		Los Angeles Basin	18	19	19	18

Total	Total	55	55		Total	51	53	53	55
NGLs (MBbl/d)	NGLs (MBbl/d)				NGLs (MBbl/d)
San Joaquin Basin	San Joaquin Basin	11	11		San Joaquin Basin	11	11	11	11

Total	Total	11	11		Total	11	11	11	11
Natural gas (MMcf/d)	Natural gas (MMcf/d)				Natural gas (MMcf/d)
San Joaquin Basin	San Joaquin Basin	119	129		San Joaquin Basin	122	119	120	128
Los Angeles Basin	Los Angeles Basin	1	1		Los Angeles Basin	1	1	1	1

Sacramento Basin	Sacramento Basin	16	17		Sacramento Basin	15	15	15	18
Total	Total	136	147		Total	138	135	136	147

Total Net Production (MBoe/d)	Total Net Production (MBoe/d)	89	91		Total Net Production (MBoe/d)	85	86	87	91

Total daily net production for the three months ended ~~March 31,~~September 30, 2023, compared to the three months ended ~~December 31, 2022~~June 30, 2023 decreased by 21 MBoe/d ~~or 2%~~ largely due to ~~higher amounts of rain and colder seasonal temperatures than normal in California which increased downtime in our operations.~~natural decline for oil. Our production-sharing contracts (PSCs), which are described below, did not have ana significant impact on our net oil production in the three months ended ~~March 31,~~September 30, 2023 compared to the three months ended ~~December 31, 2022.~~June 30, 2023.

21Total daily net production for the nine months ended September 30, 2023, compared to the same prior year period decreased by 4 MBoe/d largely due to natural decline and the divestiture of our remaining 50% working interest in certain zones in the Lost Hills field in February 2022. This decrease was partially offset by increased production from drilling and workover activity in Long Beach and our PSCs positively impacted our net production by 2 MBoe/d in the nine months ended September 30, 2023 compared to the same prior year period.

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 from fields operated by others) for the periods presented:

Three months ended
March 31, 2023 December 31, 2022
(MBoe/d)
Total Net Production 89 91
Partners' share under PSC-type contracts 6 6
Working interest and royalty holders' share 7 7
Other 1 1
Total Gross Production 103 105


	Three months ended		Nine months ended
	September 30, 2023	June 30, 2023	September 30, 2023	September 30, 2022
	(MBoe/d)
Total Net Production	85	86	87	91
Partners' share under PSC-type contracts	7	7	6	8
Working interest and royalty holders' share	7	8	8	7
Changes in NGL inventory and other	2	2	1	1
Total Gross Production	101	103	102	107

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. 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								Three months ended
		March 31, 2023				December 31, 2022					September 30, 2023				June 30, 2023
		(in millions)		($ per Boe)		(in millions)		($ per Boe)					(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs	Operating costs	$	254	$	31.61	$	199	$	23.86			Operating costs	$	196	$	24.96	$	186	$	23.71
Excess costs attributable to PSC-type contracts	Excess costs attributable to PSC-type contracts	(18)		$	(2.23)	(16)		$	(1.90)			Excess costs attributable to PSC-type contracts	(19)		$	(2.39)	(17)		$	(2.15)
Operating costs, excluding effects of PSC-type contracts	Operating costs, excluding effects of PSC-type contracts	$	236	$	29.38	$	183	$	21.96			Operating costs, excluding effects of PSC-type contracts	$	177	$	22.57	$	169	$	21.56


	Nine months ended
	September 30, 2023				September 30, 2022
	(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs	$	636	$	26.80	$	586	$	23.71
Excess costs attributable to PSC-type contracts	(54)		$	(2.26)	(58)		$	(2.35)
Operating costs, excluding effects of PSC-type contracts	$	582	$	24.54	$	528	$	21.36

For further information on our production-sharing contracts, see Part I, Item 1 & 2 Business and Properties, Oil and Natural Gas Operations, Production, Price and Cost History in our 2022 Annual Report.

2228

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						Three months ended
		March 31, 2023			December 31, 2022				September 30, 2023				June 30, 2023
		Price		Realization	Price		Realization				Price		Realization	Price		Realization
Oil ($ per Bbl)	Oil ($ per Bbl)									Oil ($ per Bbl)
Brent	Brent	$	82.22		$	88.60				Brent	$	85.95		$	78.01

Realized price without derivative settlements	Realized price without derivative settlements	$	78.68	96%	$	87.15	98%			Realized price without derivative settlements	$	85.36	99%	$	75.77	97%
Effects of derivative settlements		(15.64)			(25.82)
Derivative settlements										Derivative settlements	(19.24)			(12.11)
Realized price with derivative settlements	Realized price with derivative settlements	$	63.04	77%	$	61.33	69%			Realized price with derivative settlements	$	66.12	77%	$	63.66	82%

WTI	WTI	$	76.13		$	82.64				WTI	$	82.26		$	73.78

Realized price without derivative settlements	Realized price without derivative settlements	$	78.68	103%	$	87.15	105%			Realized price without derivative settlements	$	85.36	104%	$	75.77	103%
Realized price with derivative settlements	Realized price with derivative settlements	$	63.04	83%	$	61.33	74%			Realized price with derivative settlements	$	66.12	80%	$	63.66	86%

NGLs ($ per Bbl)	NGLs ($ per Bbl)									NGLs ($ per Bbl)
Realized price (% of Brent)	Realized price (% of Brent)	$	58.88	72%	$	56.55	64%			Realized price (% of Brent)	$	44.95	52%	$	42.48	54%
Realized price (% of WTI)	Realized price (% of WTI)	$	58.88	77%	$	56.55	68%			Realized price (% of WTI)	$	44.95	55%	$	42.48	58%

Natural gas	Natural gas									Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	3.42		$	6.26				NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	2.55		$	2.10

Realized price without derivative settlements ($/Mcf)		$	21.56	630%	$	8.73	139%
Effects of derivative settlements		—			(0.22)
Realized price with derivative settlements ($/Mcf)		$	21.56	630%	$	8.51	136%
Realized price ($/Mcf)										Realized price ($/Mcf)	$	4.83	189%	$	3.46	165%


	Nine months ended
	September 30, 2023			September 30, 2022
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	82.06		$	102.33

Realized price without derivative settlements	$	79.90	97%	$	102.01	100%
Derivative settlements	(15.65)			(40.05)
Realized price with derivative settlements	$	64.25	78%	$	61.96	61%

WTI	$	77.39		$	98.09

Realized price without derivative settlements	$	79.90	103%	$	102.01	104%
Realized price with derivative settlements	$	64.25	83%	$	61.96	63%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	48.89	60%	$	66.98	65%
Realized price (% of WTI)	$	48.89	63%	$	66.98	68%

Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	2.69		$	6.77

Realized price without derivative settlements ($/Mcf)	$	9.85	366%	$	7.33	108%
Derivative settlements	—			(0.12)
Realized price with derivative settlements ($/Mcf)	$	9.85	366%	$	7.21	106%

Oil — Brent prices ~~decreased~~increased for the three months ended ~~March 31,~~September 30, 2023 compared to the three months ended ~~December 31, 2022 due to recession concerns across Western economies~~June 30, 2023 as OPEC and ~~disappointment at the pace and scale of the post-COVID-19 reopening~~Saudi Arabia announced extended production cuts in ~~China. Our realizations without derivative settlements also declined to 96%~~September 2023. Oil prices in the ~~three~~nine months ended ~~March 31,~~September 30, 2023 ~~compared to 98%~~were lower than the same prior year period in ~~the three months ended December 31,~~ 2022 as ~~a result of lower local posting prices relative~~global energy inventories (including crude, refined products and natural gas) stabilized and as Russian crude and refined products continued to ~~Brent pricing.~~reach markets.

NGLs — NGL prices for the three months ended ~~March 31,~~September 30, 2023 increased compared to the three months ended ~~December 31, 2022 as a result of cooler-than-normal weather~~June 30, 2023 in ~~California, which led to higher~~concert with crude pricing. NGL prices for the nine months ended September 30, 2023 decreased compared to the same prior year period as prices for competing and complementary products (natural gas, crude oil) have declined and as NGL ~~products including propane which is generally used for heating, among~~production and inventories grew to near-record levels. For both periods, California remained a premium market compared to other ~~things.~~North American locations.

Natural Gas — Our realized price for natural gas increased for the three months ended ~~March 31,~~September 30, 2023 as compared to the three months ended ~~December 31, 2022 due to higher demand as a result of colder weather across the West Coast of the United States. In addition, inventory levels~~June 30, 2023 driven by incremental gas-fired electrical generation and replenishment of natural gas storage inventories. Natural gas prices in the nine months ended September 30, 2023 were higher than the same period in 2022 largely reflecting the unusually high pricing experienced in California ~~were lower than typical for this time~~natural gas markets during the first quarter of ~~year which further contributed to this increase.~~2023.

2330

Statements of Operations Analysis

Results of Oil and Gas Operations

The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses, on a per Boe basis for the three months ended ~~March 31,~~September 30, 2023 and ~~December 31,~~June 30, 2023 and the nine months ended September 30, 2023 and 2022. 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.


		Three months ended					Three months ended		Nine months ended
		March 31, 2023		December 31, 2022					September 30, 2023		June 30, 2023		September 30, 2023		September 30, 2022
		($ per Boe)				($ per Boe)
Energy operating costs	Energy operating costs	$	15.56	$	9.56			Energy operating costs	$	9.42	$	7.39	$	10.87	$	9.83
Gas processing costs	Gas processing costs	$	0.62	$	0.48			Gas processing costs	$	0.64	$	0.64	$	0.59	$	0.53
Non-energy operating costs	Non-energy operating costs	$	15.43	$	13.82			Non-energy operating costs	$	14.90	$	15.68	$	15.34	$	13.35
Operating costs	Operating costs	$	31.61	$	23.86			Operating costs	$	24.96	$	23.71	$	26.80	$	23.71

Field general and administrative expenses(a)	Field general and administrative expenses(a)	$	1.49	$	1.32			Field general and administrative expenses(a)	$	1.27	$	1.40	$	1.39	$	1.01
Field depreciation, depletion and amortization(b)	Field depreciation, depletion and amortization(b)	$	6.72	$	5.27			Field depreciation, depletion and amortization(b)	$	6.62	$	6.50	$	6.62	$	5.30
Field taxes other than on income	Field taxes other than on income	$	3.73	$	3.36			Field taxes other than on income	$	4.33	$	3.70	$	3.92	$	3.36

a.(a)Excludes unallocated general and administrative expenses.

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

Operating costs increased during the three months ended ~~March 31,~~September 30, 2023 compared to the three months ended ~~December 31, 2022~~June 30, 2023 primarily due to higher energy operating costs as electricity and natural gas prices in ~~California.~~California markets increased between quarters. Operating costs were higher in the nine months ended September 30, 2023 compared to the same prior year period primarily due to increased energy operating costs as well as increased downhole maintenance activity in 2023. Lower production volumes also contributed to the increase on a per Boe basis.

Field depreciation, depletion and amortization increased during the ~~three~~nine months ended ~~March 31,~~September 30, 2023 compared to the ~~three months ended December 31, 2022~~same prior year period primarily due to a change in our depreciation, depletion and amortization ~~rate for~~rates which are periodically adjusted to reflect current reserve estimates. Lower production volumes also contributed to the ~~current year.~~increase on a per Boe basis.

Field taxes other than on income increased during the three months ended September 30, 2023 compared to the three months ended June 30, 2023, and the nine months ended September 30, 2023 compared to the same prior year period primarily due to higher ad valorem taxes in the second half of 2023, which in California are heavily influenced by commodity prices.

Consolidated Results of Operations

For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the Senior Notes Indenture, see Part I, Item 1 – Financial Statements, Note 12 Condensed Consolidated Financial Information.

Three months ended ~~March 31,~~September 30, 2023 compared to ~~December 31, 2022~~June 30, 2023

The following table presents our operating revenues for the three months ended ~~March 31,~~September 30, 2023 and ~~December 31, 2022:~~June 30, 2023:


		Three months ended					Three months ended
		March 31, 2023		December 31, 2022			September 30, 2023		June 30, 2023
		(in millions)					(in millions)
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	715	$	617	Oil, natural gas and NGL sales	$	510	$	447
Net gain (loss) from commodity derivatives		42		(132)
Sales of purchased natural gas		184		94
Net (loss) gain from commodity derivatives						Net (loss) gain from commodity derivatives	(204)		31
Marketing of purchased natural gas						Marketing of purchased natural gas	78		72
Electricity sales	Electricity sales	68		90		Electricity sales	67		34
Other revenue	Other revenue	15		13		Other revenue	9		7
Total operating revenues	Total operating revenues	$	1,024	$	682	Total operating revenues	$	460	$	591

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were ~~$715~~$510 million for the three months ended ~~March 31,~~September 30, 2023, which is an increase of ~~$98~~$63 million compared to ~~$617~~$447 million for the three months ended ~~December 31, 2022.~~June 30, 2023. This increase was primarily due to ~~changes in~~higher realized prices for the third quarter of 2023, partially offset by lower oil production volumes as shown in the table ~~below, including higher realized prices for natural gas and NGLs partially offset by lower realized prices for oil.~~below. The effect of cash settlements on our commodity derivative contracts is not included in the table below.


		Oil		NGLs		Natural Gas		Total			Oil		NGLs		Natural Gas		Total
		(in millions)									(in millions)
Three months ended December 31, 2022		$	441	$	59	$	117	$	617
Three months ended June 30, 2023										Three months ended June 30, 2023	$	362	$	42	$	43	$	447
Changes in realized prices	Changes in realized prices	(43)		3		172		132		Changes in realized prices	49		3		17		69
Changes in production	Changes in production	(8)		—		(26)		(34)		Changes in production	(9)		2		1		(6)
Three months ended March 31, 2023		$	390	$	62	$	263	$	715
Three months ended September 30, 2023										Three months ended September 30, 2023	$	402	$	47	$	61	$	510

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~~Net (loss) gain from commodity ~~derivative contracts is not included in the table above. Payments on~~derivatives— Net loss from commodity derivatives ~~were $65~~was $204 million for the three months ended ~~March 31,~~September 30, 2023 compared to ~~payments~~net gain of ~~$134~~$31 million for the three months ended December 31, 2022. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $167 million, or 35% compared to the three months ended December 31, 2022.

~~Net gain (loss)~~June 30, 2023. The net loss from commodity derivatives ~~— Net gain from commodity derivatives was $42 million for the three months ended March 31, 2023 compared to a net loss of $132 million for the three months ended December 31, 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~~at the ~~table below:~~end of each measurement period.

Three months ended
March 31, 2023 December 31, 2022
(in millions)
Non-cash commodity derivative gain $ 107 $ 2
Net cash payments on settled commodity derivatives (65) (134)
Net gain (loss) from commodity derivatives $ 42 $ (132)

~~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~~Payments on commodity derivatives were ~~$184~~$95 million for the three months ended ~~March 31,~~September 30, 2023 an increase of $90 million, or 96% from $94 million during the three months ended December 31, 2022. The increase was primarily the result of higher trading activity and market prices for natural gas. Our natural gas sales net of related purchased natural gas expense were $60compared to $63 million for the three months ended ~~March 31, 2023~~June 30, 2023. Including the effect of settlement payments for commodity derivatives, the price received for our oil, natural gas and NGL sales decreased by $31 million compared to $7the three months ended June 30, 2023.


	Three months ended
	September 30, 2023		June 30, 2023
	(in millions)
Non-cash commodity derivative (loss) gain	$	(109)	$	94


Net cash payments on settled commodity derivatives	(95)		(63)

Net (loss) gain from commodity derivatives	$	(204)	$	31

Electricity sales— Electricity sales increased by $33 million to $67 million for the three months ended ~~December 31, 2022.~~

~~Electricity sales~~ ~~— Electricity sales decreased by $22 million~~September 30, 2023 compared to ~~$68~~$34 million for the three months ended ~~March 31,~~June 30, 2023 ~~compared to $90 million for the three months ended December 31, 2022. The decrease was primarily~~predominately due to ~~lower~~higher power prices induring the ~~first~~third quarter of ~~2023 compared to the fourth quarter of 2022.~~2023.

2532

The following table presents our operating and non-operating expenses and income for the three months ended ~~March 31,~~September 30, 2023 and ~~December 31, 2022:~~June 30, 2023:


		Three months ended					Three months ended
		March 31, 2023		December 31, 2022			September 30, 2023		June 30, 2023
		(in millions)					(in millions)
Operating expenses	Operating expenses					Operating expenses
Energy operating costs	Energy operating costs	$	125	$	80	Energy operating costs	$	74	$	58
Gas processing costs	Gas processing costs	5		4		Gas processing costs	5		5
Non-energy operating costs	Non-energy operating costs	124		115		Non-energy operating costs	117		123
General and administrative expenses	General and administrative expenses	65		59		General and administrative expenses	65		71
Depreciation, depletion and amortization	Depreciation, depletion and amortization	58		49		Depreciation, depletion and amortization	56		56
Asset impairment		3		—

Taxes other than on income	Taxes other than on income	42		42		Taxes other than on income	48		42
Exploration expense	Exploration expense	1		1		Exploration expense	—		1
Purchased natural gas expense		124		87
Purchased natural gas marketing expense						Purchased natural gas marketing expense	31		27
Electricity generation expenses	Electricity generation expenses	49		68		Electricity generation expenses	23		13
Transportation costs	Transportation costs	17		13		Transportation costs	16		16
Accretion expense	Accretion expense	12		11		Accretion expense	12		11
Other operating expenses, net	Other operating expenses, net	13		20		Other operating expenses, net	28		21
Total operating expenses	Total operating expenses	638		549		Total operating expenses	475		444
Gain (loss) on asset divestitures		7		(1)
Operating income		393		132
Gain on asset divestitures						Gain on asset divestitures	—		—
Operating (loss) income						Operating (loss) income	(15)		147

Non-operating (expenses) income	Non-operating (expenses) income					Non-operating (expenses) income

Interest and debt expense	Interest and debt expense	(14)		(14)		Interest and debt expense	(15)		(14)

Loss from investment in unconsolidated subsidiary	Loss from investment in unconsolidated subsidiary	(2)		(1)		Loss from investment in unconsolidated subsidiary	(3)		(1)
Other non-operating (expense) income		(1)		—
Income before income taxes		376		117
Income tax provision		(75)		(34)
Net income		$	301	$	83
Other non-operating income						Other non-operating income	3		3
(Loss) income before income taxes						(Loss) income before income taxes	(30)		135
Income tax benefit (provision)						Income tax benefit (provision)	8		(38)
Net (loss) income						Net (loss) income	$	(22)	$	97

Energy operating costs — Energy operating costs for the three months ended ~~March 31,~~September 30, 2023 were ~~$125~~$74 million, which was an increase of ~~$45~~$16 million ~~or 56%~~ from ~~$80~~$58 million for the three months ended ~~December 31, 2022.~~June 30, 2023. This increase ~~includes $38 million for purchased electricity and purchased~~was a result of higher natural gas which we use to generate electricity for our operations, and $7 million of purchased natural gas used to generate steam for our steamfloods. Natural gas used in our operations is purchased at first-of-the-month prices ~~which were higher than average daily prices during the period due to significant volatility~~ in the ~~natural gas market.~~third quarter of 2023. For more information on our natural gas market prices, see Prices and Realizations above.

Non-energy operating costs — Non-energy operating costs for the three months ended ~~March 31,~~September 30, 2023 were ~~$124~~$117 million ~~which was an increase of $9 million or 8% from $115~~compared to $123 million for the three months ended ~~December 31, 2022. This increase was~~June 30, 2023, which is a decrease of $6 million primarily due to a ~~result of increased~~reduction in downhole maintenance ~~activity from~~activity. Non-energy operating costs include $2 million and $3 million of stock-based compensation expense related to our cash-settled awards for the ~~prior quarter.~~three months ended September 30, 2023 and June 30, 2023, respectively. See General and administrative expenses below for additional information on our stock-based compensation awards.

2633

General and administrative expenses — General and administrative (G&A) expenses were $65 million for the three months ended ~~March 31,~~September 30, 2023, which was a decrease of $6 million from $71 million for the three months ended June 30, 2023. The decrease in G&A expenses was primarily attributable to a reduction in compensation-related expenses following a headcount reduction in August 2023.

The table below shows G&A expenses for our exploration and production business (including unallocated corporate overhead and other) separately from our carbon management business. The amounts shown for our carbon management business do not include expenses borne by the Carbon TerraVault JV.


	Three months ended
	September 30, 2023		June 30, 2023
	(in millions)
Exploration and production, corporate and other	$	61	$	68
Carbon management business	4		3
Total general and administrative expenses	$	65	$	71

Stock-based compensation awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest at the end of a two- or three-year period or vest ratably over a two- or three-year period. Our equity-settled awards granted to non-employee directors are restricted stock units that vest ratably over a three-year period. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period. Grants of equity-settled awards in 2021 contemplated that no corresponding grants would be made in 2022. Additional grants were made in 2023.

Changes in our stock price introduce volatility in our results of operations because we pay half of our cash-settled awards based on our stock price performance and we adjust our obligation for unvested cash-settled awards at the end of each reporting period. Equity-settled awards are not similarly adjusted for changes in our stock price.

Stock-based compensation included in G&A expense is shown in the table below:


	Three months ended
	September 30, 2023		June 30, 2023
	(in millions)
Cash-settled awards	$	3	$	5
Stock-settled awards	7		8
Total included in general and administrative expenses	$	10	$	13

Electricity generation expenses— Electricity generation expenses for the three months ended September 30, 2023 were $23 million, which was an increase of $10 million from $13 million for the three months ended June 30, 2023. This increase was primarily due to higher prices for natural gas.

Income taxes– The income tax benefit for the three months ended September 30, 2023 was $8 million (representing an effective tax rate of 27%), compared to a provision of $38 million (representing an effective tax rate of 28%) for the three months ended June 30, 2023.

Nine months ended September 30, 2023 compared to September 30, 2022

The following table presents our operating revenues for the nine months ended September 30, 2023 and 2022:


	Nine months ended
	September 30, 2023		September 30, 2022
	(in millions)
Oil, natural gas and NGL sales	$	1,672	$	2,026
Net loss from commodity derivatives	(131)		(419)
Marketing of purchased natural gas	334		220
Electricity sales	169		171
Other revenue	31		27
Total operating revenues	$	2,075	$	2,025

Oil, natural gas and NGL sales— Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $1,672 million for the nine months ended September 30, 2023, which is a decrease of $354 million compared to $2,026 million for the nine months ended September 30, 2022. This decrease was primarily due to changes in realized prices as shown in the table below, including lower realized prices for oil and NGLs, partially offset by higher realized prices for natural gas. The effect of cash settlements on our commodity derivative contracts is not included in the table below.


	Oil		NGLs		Natural Gas		Total
	(in millions)
Nine months ended September 30, 2022	$	1,527	$	205	$	294	$	2,026
Changes in realized prices	(331)		(55)		101		(285)
Changes in production	(42)		1		(28)		(69)
Nine months ended September 30, 2023	$	1,154	$	151	$	367	$	1,672

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

Net loss from commodity derivatives— Net loss from commodity derivatives was $131 million for the nine months ended September 30, 2023 compared to a net loss of $419 million for the nine months ended September 30, 2022. The net loss from commodity derivatives primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each measurement period.

Payments on commodity derivatives were $223 million for the nine months ended September 30, 2023 compared to payments of $604 million for the nine months ended September 30, 2022. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $27 million compared to the nine months ended September 30, 2022.


	Nine months ended
	September 30, 2023		September 30, 2022
	(in millions)
Non-cash commodity derivative gain	$	92	$	185


Net cash payments on settled commodity derivatives	(223)		(604)

Net loss from commodity derivatives	$	(131)	$	(419)

Marketing of purchased natural gas— Marketing of purchased natural gas relates to natural gas acquired from third parties which is subsequently sold in connection with certain of our marketing activities. Marketing of purchased natural gas were $334 million for the nine months ended September 30, 2023, an increase of $114 million from $220 million during the nine months ended September 30, 2022. The increase was primarily the result of higher prices during 2023, which peaked in January 2023. Revenues from marketing of purchased natural gas net of related purchased natural gas marketing expense were $152 million for the nine months ended September 30, 2023 compared to $34 million for the nine months ended September 30, 2022.

The following table presents our operating and non-operating expenses and income for the nine months ended September 30, 2023 and 2022:


	Nine months ended
	September 30, 2023		September 30, 2022
	(in millions)
Operating expenses
Energy operating costs	$	258	$	243
Gas processing costs	14		13
Non-energy operating costs	364		330
General and administrative expenses	201		163
Depreciation, depletion and amortization	170		149
Asset impairment	3		2
Taxes other than on income	132		120
Exploration expense	2		3
Purchased natural gas marketing expense	182		186
Electricity generation expenses	85		99
Transportation costs	49		37
Accretion expense	35		32
Other operating expenses, net	62		28
Total operating expenses	1,557		1,405
Gain on asset divestitures	7		60
Operating income	525		680

Non-operating (expenses) income

Interest and debt expense	(43)		(39)

Loss from investment in unconsolidated subsidiary	(6)		—
Other non-operating income	5		3
Income before income taxes	481		644
Income tax provision	(105)		(203)
Net income	$	376	$	441

Energy operating costs — Energy operating costs for the nine months ended September 30, 2023 were $258 million, which was an increase of $15 million from $243 million for the nine months ended September 30, 2022. This increase was a result of higher prices in the nine months of 2023 compared to the same prior year period. For more information on our natural gas market prices, see Prices and Realizations above.

Non-energy operating costs — Non-energy operating costs were $364 million for the nine months ended September 30, 2023, which was an increase of $6$34 million from ~~$59~~$330 million for the ~~three~~nine months ended ~~December 31,~~September 30, 2022. The increase was predominately a result of higher downhole maintenance activity. Non-energy operating costs also includes $6 million and $3 million of stock-based compensation expense related to our cash-settled awards for the nine months ended September 30, 2023 and 2022, respectively. See General and administrative expenses below for additional information on our stock-based compensation awards.

General and administrative expenses — General and administrative (G&A) expenses were $201 million for the nine months ended September 30, 2023, which was an increase of $38 million from $163 million for the nine months ended September 30, 2022. The increase in G&A expenses was primarily attributable to compensation-related expenses, ~~including~~related to stock-based compensation awards granted in ~~the first quarter~~2023 that had not been granted in 2022. Grants of ~~2023.~~ equity-settled awards in 2021 following our emergence from bankruptcy contemplated that no corresponding grants would be made in 2022. G&A expenses also increased to a lesser extent due to increased headcount in our carbon management business, and higher spending to streamline our information technology infrastructure. Stock-based compensation awards are discussed further below.

The table below shows G&A expenses for our exploration and production business (in addition to unallocated corporate overhead and other) separately from our carbon management business. The amounts shown for our carbon management business ~~are net of amounts reimbursable to us under the MSA with~~do not include expenses borne by the Carbon TerraVault JV.


		Three months ended					Nine months ended
		March 31, 2023		December 31, 2022			September 30, 2023		September 30, 2022
		(in millions)					(in millions)
Exploration and production, corporate and other	Exploration and production, corporate and other	$	62	$	57	Exploration and production, corporate and other	$	191	$	153
Carbon management business	Carbon management business	3		2		Carbon management business	10		10
Total general and administrative expenses	Total general and administrative expenses	$	65	$	59	Total general and administrative expenses	$	201	$	163

Awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest at the end of a two- or three-year period or vest ratably over a two- or three-year period. Our equity-settled awards granted to non-employee directors are restricted stock units that vest ratably over a three-year period. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period.

Stock-based compensation included in G&A expense is shown in the table below:


	Nine months ended
	September 30, 2023		September 30, 2022
	(in millions)
Cash-settled awards	$	11	$	6
Stock-settled awards	21		13
Total included in general and administrative expenses	$	32	$	19

Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) increased $9$21 million to ~~$58~~$170 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2023 from ~~$49~~$149 million for the ~~three~~nine months ended ~~December 31,~~September 30, 2022. The increase was primarily due to a change in our DD&A ~~rate for the~~rates which are periodically adjusted to reflect current ~~year.~~reserve estimates.

~~Purchased natural gas expense~~Taxes other than on income — ~~Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. We purchased $124~~Taxes other than on income were $132 million ~~of natural gas~~ for ~~marketing activities during~~ the ~~three~~nine months ended ~~March 31,~~September 30, 2023, which was an increase of ~~$37~~$12 million ~~or 43%~~ from ~~$87~~$120 million for the ~~three~~nine months ended ~~December 31,~~September 30, 2022. The increase was ~~predominantly the result of~~primarily related to higher ~~trading activity levels and natural gas market prices~~ad valorem taxes in ~~the three months ended March 31, 2023 compared to the three months ended December 31, 2022. For more information on our natural gas market prices, see~~ ~~Prices and Realizations~~ ~~above.~~2023.

Electricity generation ~~expenses~~ expense— Electricity generation expenses for the ~~three~~nine months ended ~~March 31,~~September 30, 2023 were ~~$49~~$85 million, which was a decrease of ~~$19~~$14 million ~~or 28%~~ from ~~$68~~$99 million for the ~~three months ended December 31, 2022.~~same prior year period. This decrease was primarily due to ~~volatility in the~~lower prices for natural gas. ~~Natural gas used~~

Transportation costs— Transportation costs increased by $12 million to $49 million for ~~electricity generation at our Elk Hills power plant is purchased on~~the nine months ended September 30, 2023 from $37 million for the nine months ended September 30, 2022. The increase in transportation costs was a ~~daily basis as opposed to the first-of-the-month prices paid for gas used in our operations. There was significant volatility for~~result of higher natural gas ~~prices~~marketing activities.

Other operating expenses, net — Other operating expenses, net were $62 million for the nine months ended September 30, 2023, which was an increase of $34 million from $28 million during the same prior year period. The increase was primarily related to costs to implement operational efficiencies in ~~California that led~~2023, including severance, and higher expenses related to ~~much lower daily prices than first-of-the-month prices.~~our carbon management.

The table below shows other operating expenses, net for our exploration and production business (including unallocated corporate overhead and other) separately from our carbon management business. Carbon management expenses include lease cost for carbon sequestration easements, advocacy, technical evaluation of carbon storage and other startup related costs. The amounts shown for our carbon management business do not include expenses borne by the Carbon TerraVault JV.


	Nine months ended September 30,
	2023		2022
	(in millions)
Exploration and production, corporate and other	$	41	$	25
Carbon management business	21		3
Total other operating expenses, net	$	62	$	28

Income taxes – The income tax provision for the ~~three~~nine months ended ~~March 31,~~September 30, 2023 was ~~$75~~$105 million ~~(effective~~(representing an effective tax rate of ~~20%~~22%), compared to ~~$34~~$203 million ~~(effective~~(representing an effective tax rate of ~~29%~~32%) for the ~~three~~nine months ended ~~December 31,~~September 30, 2022. ~~Excluding~~The income tax provision for the ~~effect of the change in~~nine months ended September 30, 2022 included a valuation allowance related to our ~~effective tax rate would be 28%~~Lost Hills divestiture that was released in the ~~three~~nine months ended ~~March 31, 2023 compared to 29% in the three months ended December 31, 2022.~~September 30, 2023. See Part I, Item 1 – Financial Statements, Note 6 Income Taxes for more information on a valuation allowance related to our Lost Hills divestiture.

Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity and capital resources are cash flows from operations, cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. ~~See~~ ~~Part I, Item 1 – Financial Statements, Note 14 Subsequent Events~~ ~~for more information on an April 2023 amendment to our Revolving Credit Facility.~~ We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the ~~three~~nine months ended ~~March 31,~~September 30, 2023 were for capital investments, repurchases of our common stock and dividends. Refer to Part I, Item 1 – Financial Statements, Note 3 Debt for information on repurchases of our Senior Notes. In October 2023, we repurchased an additional $30 million of our Senior Notes at an average price of 100.50% of par. Following these repurchases, the remaining principal amount of our outstanding Senior Notes is $565 million.

The following table summarizes our liquidity:



	~~March 31,~~September 30, 2023
	(in millions)
Cash and cash equivalents	$	~~477~~479
Revolving Credit Facility:
Borrowing capacity(a)	~~602~~627
Outstanding letters of credit	(148)
Availability	$	~~454~~479

Liquidity	$	~~931~~958

(a)

~~On April 26,~~As part of the October 30, 2023 ~~the borrowing base under~~amendment to our Revolving Credit Facility, ~~was reaffirmed at $1.2 billion.~~our borrowing capacity increased by $3 million to $630 million.

We recently amended our Revolving Credit Facility as described in Part I, Item 1 – Financial Statements, Note 3 Debt and Note 13 Subsequent Events, and continue to evaluate refinancing options for our Senior Notes. We also intend to pursue financing options for our carbon management business that are separate from the rest of our business.

At current commodity prices and based upon our planned 2023 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) repurchase outstanding indebtedness, (iv) advance carbon management activities, or ~~(iv)~~(v) maintain cash and cash equivalents on our balance sheet. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.

Cash Flow Analysis

Cash flows from operating activities — For the ~~three~~nine months ended ~~March 31,~~September 30, 2023, our operating cash flow ~~increased 94%, or $150~~decreased $54 million to ~~$310~~$522 million from ~~$160~~$576 million in the same ~~prior~~ period ofin 2022. The ~~increases~~decreases in operating cash flow for the ~~three~~nine months ended ~~March 31,~~September 30, 2023 primarily relates to ~~higher~~lower average realized oil prices ~~(including the effects of settlements on our commodity derivatives)~~as well as production volumes in 2023 compared to the same prior-year period. This increase was partially offset by lower production volumes in 2023 as compared to the same period in 2022. 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.

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


		Three months ended March 31,						Nine months ended September 30,
			2023		2022				2023		2022
			(in millions)						(in millions)
Capital investments	Capital investments		$	(47)	$	(99)	Capital investments		$	(119)	$	(304)
Changes in accrued capital investments	Changes in accrued capital investments		(13)		3		Changes in accrued capital investments		(10)		5
Proceeds from divestitures, net	Proceeds from divestitures, net		—		60		Proceeds from divestitures, net		—		79
Acquisitions	Acquisitions		—		(17)		Acquisitions		(1)		(17)

Other			(1)		—
Distribution related to the Carbon TerraVault JV							Distribution related to the Carbon TerraVault JV		—		12
Capitalized joint venture transaction costs							Capitalized joint venture transaction costs		—		(12)
Other, net							Other, net		(3)		(1)
Net cash used in investing activities	Net cash used in investing activities		$	(61)	$	(53)	Net cash used in investing activities		$	(133)	$	(238)

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


		Three months ended March 31,						Nine months ended September 30,
			2023		2022				2023		2022
			(in millions)						(in millions)

Repurchases of common stock	Repurchases of common stock		$	(59)	$	(71)	Repurchases of common stock		$	(143)	$	(247)
Common stock dividends	Common stock dividends		(20)		(13)		Common stock dividends		(59)		(39)

Issuance of common stock	Issuance of common stock		1		$	—	Issuance of common stock		1		$	1
Debt amendment costs							Debt amendment costs		(8)		$	—
Debt repurchases							Debt repurchases		(5)		$	—
Shares cancelled for taxes	Shares cancelled for taxes		(1)		$	—	Shares cancelled for taxes		(3)		$	—
Net cash used in financing activities	Net cash used in financing activities		$	(79)	$	(84)	Net cash used in financing activities		$	(217)	$	(285)

2023 Capital Program

Our capital program is dynamic in response to commodity price volatility while focusing on oil production and maximizing our free cash flow. We expect our 2023 capital program to range between ~~$200~~$185 and ~~$245~~$210 million under current ~~conditions. We expect~~conditions with continuing focus on high return workover activity and facilities projects. For the remainder of 2023, we will execute a one rig program in the Los Angeles basin. Our level of spending in the fourth quarter of 2023 includes procuring critical components for planned maintenance at our ~~capital program related~~power plant and a gas processing facility at Elk Hills in 2024 as well as incremental spending to ~~oil and natural gas development to be focused primarily on executing projects using existing permits outside of Kern County.~~advance our carbon management business.

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


	2023 Full Year Estimate	~~Three~~Nine months ended ~~March 31,~~September 30, 2023
	(in millions)
Oil and natural gas operations	$~~165~~ 155 - ~~$195~~170	$	40106
Carbon management business	5 - 1510	1
Corporate and other	3025 - 3530	612
Total Capital	$~~200~~ 185 - ~~$245~~210	$	47119

~~We recently amended and extended our Revolving Credit Facility as described in~~ ~~Part I, Item 1 – Financial Statements, Note 14 Subsequent Events~~, and are currently evaluating refinancing options for our Senior Notes, which we expect to provide us with greater operating and financial flexibility to bolster our ongoing shareholder return program. We also intend to pursue financing options for our carbon management business that are separate from the rest of our business.

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. 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 ~~March 31,~~September 30, 2023. See Part I, Item 1 – Financial Statements, Note 5 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of ~~March 31,~~September 30, 2023 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2022 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

Dividends

~~On February 23, 2023, our~~Our Board of Directors declared ~~a quarterly~~the following cash ~~dividend~~dividends in each of ~~$0.2825 per share of common stock and amounted to $20 million in~~ the ~~aggregate.~~ periods presented.


	Total Dividend		Rate Per Share
	(in millions)		($ per share)
2023
Three months ended March 31, 2023	$	20	$	0.2825
Three months ended June 30, 2023	20		$	0.2825
Three months ended September 30, 2023	19		$	0.2825
Nine months ended September 30, 2023	$	59
2022
Three months ended March 31, 2022	$	13	$	0.1700
Three months ended June 30, 2022	13		$	0.1700
Three months ended September 30, 2022	13		$	0.1700
Nine months ended September 30, 2022	$	39

The ~~dividend was payable to shareholders of record at the close of business on March 6, 2023 and was paid on March 16, 2023.~~ On April 28, 2023, 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 June 1, 2023 and is expected to be paid on June 16, 2023. 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. For information regarding past dividends paid, see Cash Flow Analysis, Cash Flow Used in Financing Activities above. See Note 13 Subsequent Events for information regarding a recent increase to our dividend policy.

Share Repurchase Program

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.1 billion of our common stock through June 30, 2024. 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. The aggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $497 million, excluding commissions and excise taxes on repurchases, as of September 30, 2023. The following is a summary of our share repurchases, held as treasury stock for the periods presented:


	Total Number of Shares Purchased	Total Value of Shares Purchased		Average Price Paid per Share
	(number of shares)	(in millions)		($ per share)
Three months ended September 30, 2022	1,921,181	$	80	$	41.78
Three months ended September 30, 2023	365,145	$	20	$	54.75

Nine months ended September 30, 2022	5,845,082	$	247	$	42.29
Nine months ended September 30, 2023	3,407,655	$	143	$	41.69

Inception of Program (May 2021) through September 30, 2023	14,863,915	$	604	$	40.53

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 ~~March 31,~~September 30, 2023 and 2022.

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 ~~March 31,~~September 30, 2023 and December 31, 2022 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 4 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 2022 Annual Report.

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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, including supply and demand considerations for our products and services;

•decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods;

•government policy, war and political conditions and events, including the ~~war~~wars in Ukraine and Israel and oil sanctions on Russia, Iran and others;

•regulatory actions and changes that affect the oil and gas industry generally and us in particular, including (1) the availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities or our carbon management business; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of our products;

•the impact of inflation on future expenses and changes generally in the prices of goods and services;

•changes in business strategy and our capital plan;

•lower-than-expected production or higher-than-expected production decline rates;

•changes to our estimates of reserves and related future cash flows, including changes arising from our inability to develop such reserves in a timely manner, and any inability to replace such reserves;

•the recoverability of resources and unexpected geologic conditions;

•general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets;

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

•the lack of available equipment, service or labor price inflation;

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

•any failure of risk management;

•results from operations and competition in the industries in which we operate;

•our ability to realize the anticipated benefits from prior or future efforts to reduce costs;

•environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions);

• the creditworthiness and performance of our counterparties, including financial institutions, operating partners, CCS project participants and other parties;

•reorganization or restructuring of our operations;

•our ability to claim and utilize tax credits or other incentives in connection with our CCS projects;

•our ability to realize the benefits contemplated by our energy transition strategies and initiatives, including CCS 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, and our ability to convert our CDMAs to definitive agreements and enter into other offtake agreements;

•our ability to maximize the value of our carbon management business and operate it on a stand alone basis;

•our ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;

•uncertainty around the accounting of emissions and our ability to successfully

gather and verify emissions data and other environmental impacts;

•changes to our dividend policy and share repurchase program, and our ability to declare future dividends or repurchase shares under our debt agreements;

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

•insufficient cash flow to fund our capital plan and other planned investments and return capital to shareholders;

•changes in interest rates;

•our access to and the terms of credit in commercial banking and capital markets, including our ability to refinance our debt or obtain separate financing for our carbon management business;

•changes in state, federal or international tax rates, including our ability to utilize our net operating loss carryforwards to reduce our income tax obligations;

•effects of hedging transactions;

•the effect of our stock price on costs associated with incentive compensation;

•inability to enter into desirable transactions, including joint ventures, divestitures of oil and natural gas properties and real estate, and acquisitions, and our ability to achieve any expected synergies;

•disruptions due to earthquakes, forest fires, floods, extreme weather events or other natural occurrences, accidents, mechanical failures, power outages, transportation or storage constraints, labor difficulties, cybersecurity breaches or attacks or other catastrophic events;

•pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19 pandemic; and

•other factors discussed in Part I, Item 1A – Risk Factors in our 2022 Annual Report.

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.

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Item 3Quantitative and Qualitative Disclosures About Market Risk

For the three and nine months ended ~~March 31,~~September 30, 2023, 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 2022 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 ~~March 31,~~September 30, 2023, we had a net ~~liabilities~~liability of ~~$111~~$138 million for our commodity derivative ~~commodity~~ positions which are carried at fair value. For more information on our derivative positions as of ~~March 31,~~September 30, 2023, refer to Part I, Item 1 – Financial Statements, Note 5 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 ~~March 31,~~September 30, 2023, the majority of our credit exposure was with investment-grade counterparties. We believe exposure to counterparty credit-related losses related to our business at ~~March 31,~~September 30, 2023 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 ~~March 31,~~September 30, 2023. Our Senior Notes bear interest at a fixed rate of 7.125% per annum.

Item 4 Controls and Procedures

Our Chief Executive Officer ~~(acting as both principal executive officer~~ and ~~principal financial officer)~~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 ~~(acting as both principal executive officer~~ and ~~principal financial officer)~~our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of ~~March 31,~~September 30, 2023.

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 ~~March 31,~~September 30, 2023 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II OTHER INFORMATION

Item 1Legal Proceedings

For additional information regarding legal proceedings, see Item 1 – Financial Statements, Note 4 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 2022 Annual Report.

On September 14, 2023, the Center for Biological Diversity filed a writ petition against the City of Long Beach and the State of California, naming us and our subsidiary, the THUMS Long Beach Company, as Real Parties in Interest. The Petition generally alleges that the City of Long Beach, the Long Beach City Council, and the California State Lands Commission violated the California Environmental Quality Act by failing to evaluate the environmental impacts of certain activities (drilling and injection) authorized under Long Beach’s 2023 Annual Plan and 2023-2028 Program Plan for the Long Beach Unit, both of which received final approval in May 2023. The Petition seeks the setting aside of the approvals of the Plans and the enjoinment of any activities described thereunder until the requirements of CEQA are met; namely that an environmental review is completed. We believe the City and the State have strong defenses and we intend to vigorously defend against the Petition as a Real Party in Interest. However, we cannot predict the ultimate outcome of this action with certainty.

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 2022 Annual ~~Report.~~Report and our Quarterly Report on Form 10-Q for the three months ended March 31, 2023 and June 30, 2023. Except as set forth below, there were no material changes to those risk factors during the three months ended ~~March 31,~~September 30, 2023.

We may face material delays related to our ability to timely obtain permits necessary for our operations, or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments.

We must obtain various governmental permits to conduct exploration and production activities, as well as other aspects of our operations. Obtaining the necessary governmental permits is often a complex and time-consuming process involving numerous federal, state and local agencies. The duration and success of each permitting effort is contingent upon many variables not within our control. In the context of obtaining permits or approvals, the Company will need to comply with known standards, existing laws (such as CEQA), and regulations that may entail greater or lesser costs and delays depending on the nature of the activity to be permitted and the interpretation of the laws and regulations implemented by the permitting authority.

From time to time we have experienced significant delays with respect to obtaining drilling permits for our operations. A variety of factors outside of our control can lead to such delays. CalGEM has not issued any permits for new production wells to any operators since December 2022.

We have experienced delays obtaining permits as a result of litigation related to the Kern County EIR. On January 26, 2023, an appellate court issued a preliminary order reinstating a suspension of Kern County’s ability to rely on an existing Environmental Impact Report (EIR) to meet the County’s obligations under CEQA in connection with oil and gas permitting. The original suspension was put in place in October 2021 in response to a lawsuit challenging the adequacy of that EIR for CEQA purposes. The county subsequently issued a supplemental EIR and took other steps to address the issues raised by the original lawsuit and in November 2022 a trial court approved the sufficiency of the supplemental EIR and lifted the suspension on Kern County’s reliance on the EIR. The preliminary order of the appellate court referenced above is still pending. While we can and intend to address CEQA compliance for our oil and natural gas permitting process through alternative pathways, this would be a lengthy process and we cannot predict whether we would be able to timely obtain permits using this alternative. As a result of these issues and current lack of permits with respect to our Kern County properties, we do not currently plan to drill and complete any additional wells within Kern County until permitting is resumed in Kern County, which may be later in the 2024 calendar year. However, there is no certainty that we will obtain permits on that timeline or at all, which may further adversely affect our future development plans, proved undeveloped reserves, business, operations, cash flows, financial position, and results of operation. As of December 31, 2022, approximately 71% of our proved undeveloped reserves or 9% of our total proved reserves relate to wells to be drilled in Kern County beginning in 2024 for which we would need to obtain permits.

We have also experienced delays obtaining drilling permits from CalGEM since the passage of Senate Bill No. 1137, which established 3,200 feet as the minimum distance between new oil and natural gas production wells and certain sensitive receptors such as homes, schools and businesses open to the public (a “setback zone”). The law became effective January 1, 2023 and CalGEM issued emergency regulations implementing the requirements of the law on January 6, 2023. However, on February 3, 2023, the Secretary of State of California certified voter signatures collected in connection with a referendum for the November 2024 ballot to repeal Senate Bill No. 1137. As a result, any implementation of Senate Bill No. 1137 is stayed until it is put to a vote, although any stay could be delayed if there are legal challenges to the Secretary of State’s certification. In addition, even during the stay, CalGEM could attempt to initiate new rulemaking with respect to setbacks. There is significant uncertainty with respect to the ability to book proved undeveloped reserves and drill within the setback zone established by Senate Bill No. 1137 and, as a result, we have only booked proved undeveloped reserves for which we already have permits within the zone and intend to develop prior to the November 2024 ballot. As of December 31, 2022, changes in our development plans due to Senate Bill No. 1137 reduced the net present value of our proved undeveloped reserves by 24% and our overall proved reserves by 4%. A legislator recently introduced a bill in the California Senate providing for liability for certain adverse health conditions in a setback zone, subject to limited defenses. If the subject bill in its current preliminary form was ultimately passed by both houses of the legislature and enacted, the legislation would further impact our ability to operate in a setback zone and increase our exposure to liability.

In addition, commencing in February 2023, CalGEM began returning our applications for permits in the Wilmington Oil Field, including permits for new production wells, workovers and plugging and abandonment operations. See ~~Part I, Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Updates~~.Recent ~~changes in CalGEM management have further lead to additional permitting delays and uncertainty with respect to our ability to timely obtain permits for our operations.~~

We cannot guarantee that these issues or new ones that may arise in the future will not continue to delay or otherwise impair our ability to obtain drilling permits. In the past we have generally been able to mitigate permitting risks by building up a reserve of drilling permits for use throughout the year, but as a result of the issues described above we have not been able to build our reserve of approved permits to the same level as we have in the past. If we cannot obtain new drilling permits in a timely manner, we have limited options to meet our drilling plans that may not ultimately be sufficient to achieve our business goals. Accordingly, the failure to obtain certain permits or the adoption of more stringent permitting requirements could have a material adverse effect on our business, operations, properties, results of operations, and our financial condition.

~~Recent and future actions~~action by the State of California ~~could reduce both~~imposing additional financial assurance requirements related to plugging and abandonment costs, decommissioning, and site restoration on those who acquire the ~~demand for and supply of oil and natural gas within the state and consequently have a material and adverse effect on our business, results of operations and financial condition.~~

In recent years, the Governor of California, the Legislature and state agencies have taken a series of actions that could materially and adversely affect the state's oil and natural gas sector. 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 natural gas productionright to operate wells and certain sensitive receptors such as homes, schools or parks. Senate Bill No. 1137 is currently stayed pending the outcome of the California General Election in November 2024. A legislator recently introduced a bill in the California Senate providing for liability for certain adverse health conditions in a setback zone, subject to limited defenses. If the subject bill in its current preliminary form was ultimately passed by both houses of the legislature and enacted, the legislation would furtherproduction facilities could impact our ability to ~~operate~~sell or acquire assets in ~~a setback zone and~~the state of California or increase our ~~exposure to liability. For additional information, see~~ ~~Part I, Item 1 and 2 – Business and Properties, Regulation of~~costs in connection with the ~~Industries in Which We Operate, Regulation of Exploration and Production Activities~~ ~~in our 2022 Annual Report.~~same.

On October 7, 2023, the California Governor signed into law Assembly Bill 1167 (AB 1167), which imposes more stringent financial assurance requirements on persons who acquire the right to operate a well or production facility in the state of California, requiring them to file either an individual indemnity bond for single-well or production facility acquisitions, or a blanket indemnity bond for multiple wells or production facilities. The ~~trend~~bond imposed on the acquirer will be in ~~California is~~an amount determined by the state to ~~impose increasingly stringent restrictions~~sufficiently cover plugging and abandonment costs, decommissioning, and site restoration, and AB 1167 prohibits the closing of any acquisition of a well or production facility until a determination on ~~oil~~the appropriate bond amount has been completed by the state and ~~natural gas activities.~~the bond has been filed. We are still assessing the impact of AB 1167. In addition, although AB 1167 has been signed into law, Governor Newsom has called for further legislative changes to these new requirements to mitigate against the potential risk of the implementation of AB 1167 ultimately increasing the number of orphaned idle or low-producing wells in California. However, we cannot predict what ~~actions~~form these changes may ultimately take or if the ~~Governor~~legislature will act on the Governor’s request. Implementation of ~~California,~~this law may lead to the ~~Legislature~~delay or ~~state agencies may take in the future, but we~~additional costs with respect to acquisitions or dispositions, which could face increased compliance costs, delays in obtaining the approvals necessary for our operations, exposure to increased liability, or other limitations as a result of future actions by these parties. Moreover, new developments resulting from the current and future actions of these parties could also materially and adversely affectimpact our ability to ~~operate, successfully execute drilling plans,~~grow or ~~otherwise develop our reserves. Accordingly, recent and future actions by~~explore new strategic areas – or exit others – within the ~~Governor~~state of ~~California, the Legislature, and state agencies could materially and adversely affect our business, results of operations, and financial condition.~~

California.

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.1 billion of our common stock through June 30, 2024. 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 ~~March 31,~~September 30, 2023 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)
January 1, 2023 - January 31, 2023 467,879 $ 44.30 467,879 $ —
February 1, 2023 - February 28, 2023 322,931 $ 41.42 322,931 —
March 1, 2023 - March 31, 2023 632,954 $ 38.92 632,954 —
Total 1,423,764 $ 41.25 1,423,764 $ —


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, 2023 - July 31, 2023	—	$	—	—	$	—
August 1, 2023 - August 31, 2023	365,145	$	54.75	365,145	—
September 1, 2023 - September 30, 2023	—	$	—	—	—
Total	365,145	$	54.75	365,145	$	—

(a)The ~~dollar~~total value of shares that may yet be purchased under the Share Repurchase Program totaled ~~$581~~$497 million as of ~~March 31,~~September 30, 2023.

Item 5 Other Disclosures

~~None.~~Rule 10b5-1 Trading Arrangements

During the three months ended September 30, 2023, none of our directors or officers adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

3646

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			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 1, 2023 and incorporated herein by reference).

3.4			Amended and Restated Bylaws of California Resources Corporation (filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form 8-A filed October 27, 2020 and incorporated herein by reference).

~~10.1~~10.1,*			~~Employment Agreement by and between Francisco J. Leon and California Resources Corporation, dated February 23, 2023 (filed as Exhibit 10.25~~F irst Amendment to the ~~Registrant’s Annual Report on Form 10-K filed on February 24, 2023 and incorporated herein by reference).~~

~~10.2~~			2023 Form of California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit Award Term and Conditions (filed as Exhibit 10.26 to the Registrant’s Annual Report on Form 10-K filed on February 24, 2023 and incorporated herein by reference).

~~10.3~~			2023 Form of California Resources Corporation 2021 Long Term Incentive Plan Performance Stock Unit Award Term and Conditions (filed as Exhibit 10.27 to the Registrant’s Annual Report on Form 10-K filed on February 24, 2023 and incorporated herein by reference).

~~10.4~~			~~Form of Cash Retention Bonus Agreement (filed as Exhibit 10.28 to the Registrant’s Annual Report on Form 10-K filed on February 24, 2023 and incorporated herein by reference).~~

10.5*			Amended and Restated Credit Agreement, ~~dated~~dat ed as of ~~April~~ 26October 30 , ~~2023,~~202 3, by and ~~among~~amon g California Resources ~~Corporation,~~Corp oration, as the ~~Borrower,~~Borrowe r, the several lenders from time to time parties thereto and ~~Citibank,~~ Cit ibank, N.A., as Administrative Agent, Collateral Agent and an Issuing ~~Bank.~~Bank .

31.1*			Certification of ~~Princip~~al Principal Executive Officer ~~and~~Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*			Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*			Certifications of Principal Executive Officer and Principal Financial Officer 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 or furnished herewith

**Certain portions of this exhibit (indicated by "[*****]") have been omitted pursuant to Item 601(b)(10) of Regulation S-K

3747

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:	~~May~~November 2, 2023	/s/ Noelle M. Repetti
		Noelle M. Repetti
		Senior Vice President and Controller
		(Principal Accounting Officer)

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	Total Number of Shares Purchased	Dollar Value of Shares Purchased		Average Price Paid per Share
	(number of shares)	(in millions)		($ per share)
Three months ended March 31, 2022	1,668,456	$	71	$	42.52
Three months ended March 31, 2023	1,423,764	$	59	$	41.25

Inception of Program (May 2021) through March 31, 2023	12,880,024	$	519	$	40.31