UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September~~June 30, ~~2022~~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 ~~last~~latest practicable date.

The number of shares of common stock outstanding as of ~~September~~June 30, ~~2022~~2023 was ~~73,470,932.~~68,962,220.

California Resources Corporation and Subsidiaries

Table of Contents


	Page
Part I
Item 1	Financial Statements (unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements of ~~Comprehensive Income (Loss)~~	6
	~~Condensed Consolidated Statements of~~ Stockholders' Equity	76
	Condensed Consolidated Statements of Cash Flows	98
	Notes to the Condensed Consolidated Financial Statements	109
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
	General	24
	~~Carbon TerraVault Joint Venture~~	24
	~~Dividends~~	25
	~~Share Repurchase Program~~	25
	~~Divestitures and Acquisitions~~	25
	Business Environment and Industry Outlook	2524
	Regulatory Updates	2725
	Supply Chain Constraints and Inflation	25
	Production	2926
	Prices and Realizations	3128
	Statements of Operations Analysis	3330
	Liquidity and Capital Resources	3937
	~~2022 Capital Program~~Divestitures and Acquisitions	4039
	Lawsuits, Claims, Commitments and Contingencies	4139
	Critical Accounting Estimates and Significant Accounting and Disclosure Changes	4240
	Forward-Looking Statements	4341
Item 3	Quantitative and Qualitative Disclosures About Market Risk	4543
Item 4	Controls and Procedures	4543

Part II
Item 1	Legal Proceedings	4644
Item 1A	Risk Factors	4644
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	4645
Item 5	Other Disclosures	46
Item 6	Exhibits	47

GLOSSARY AND SELECTED ABBREVIATIONS

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

•ABR - Alternate base rate.

•ASC - Accounting Standards Codification.

•ARO - Asset retirement obligation.

•Bbl - Barrel.

•Bbl/d - Barrels per day.

•Bcf - Billion cubic feet.

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

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

•~~FEED~~ ~~- Front-end engineering design.~~

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

•GAAP - United States Generally Accepted Accounting Principles.

•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 ~~and~~ together with Russia and certain other ~~allied~~ producing ~~countries~~countries.

•~~PHMS~~PHMSA - Pipeline and Hazardous Materials Safety Administration.

•Proved developed reserves - ~~Proved 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 ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021~~2022

(in millions, except share data)


		September 30,		December 31,			June 30,		December 31,
		2022		2021			2023		2022
CURRENT ASSETS	CURRENT ASSETS					CURRENT ASSETS
Cash and cash equivalents	Cash and cash equivalents	$	358	$	305	Cash and cash equivalents	$	448	$	307
Trade receivables	Trade receivables	289		245		Trade receivables	183		326
Inventories	Inventories	59		60		Inventories	69		60
Assets held for sale	Assets held for sale	3		22		Assets held for sale	13		5
Receivable from affiliate	Receivable from affiliate	32		—		Receivable from affiliate	29		33
Other current assets		143		121
Other current assets, net						Other current assets, net	125		133
Total current assets	Total current assets	884		753		Total current assets	867		864
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT	3,126		2,845		PROPERTY, PLANT AND EQUIPMENT	3,303		3,228
Accumulated depreciation, depletion and amortization	Accumulated depreciation, depletion and amortization	(392)		(246)		Accumulated depreciation, depletion and amortization	(558)		(442)
Total property, plant and equipment, net	Total property, plant and equipment, net	2,734		2,599		Total property, plant and equipment, net	2,745		2,786
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	14		—		INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	14		13
DEFERRED TAX ASSET	DEFERRED TAX ASSET	230		396		DEFERRED TAX ASSET	108		164
OTHER NONCURRENT ASSETS	OTHER NONCURRENT ASSETS	124		98		OTHER NONCURRENT ASSETS	166		140
TOTAL ASSETS	TOTAL ASSETS	$	3,986	$	3,846	TOTAL ASSETS	$	3,900	$	3,967


CURRENT LIABILITIES	CURRENT LIABILITIES					CURRENT LIABILITIES

Accounts payable	Accounts payable	305		266		Accounts payable	206		345
Liabilities associated with assets held for sale	Liabilities associated with assets held for sale	2		21		Liabilities associated with assets held for sale	5		5
Fair value of derivative contracts		254		270
Fair value of commodity derivative contracts						Fair value of commodity derivative contracts	72		246
Accrued liabilities	Accrued liabilities	371		297		Accrued liabilities	299		298

Total current liabilities	Total current liabilities	932		854		Total current liabilities	582		894
NONCURRENT LIABILITIES	NONCURRENT LIABILITIES					NONCURRENT LIABILITIES
Long-term debt, net	Long-term debt, net	591		589		Long-term debt, net	593		592

Fair value of derivative contracts		26		132

Asset retirement obligations	Asset retirement obligations	397		438		Asset retirement obligations	411		432
Other long-term liabilities	Other long-term liabilities	185		145		Other long-term liabilities	204		185

STOCKHOLDERS' EQUITY	STOCKHOLDERS' EQUITY					STOCKHOLDERS' EQUITY
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at September 30, 2022 and December 31, 2021		—		—
Common stock (200,000,000 shares authorized at $0.01 par value) (83,406,002 and 83,389,210 shares issued; 73,470,932 and 79,299,222 shares outstanding at September 30, 2022 and December 31, 2021)		1		1
Treasury stock (9,935,070 shares held at cost at September 30, 2022 and 4,089,988 shares held at cost at December 31, 2021)		(395)		(148)
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at June 30, 2023 and December 31, 2022						Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at June 30, 2023 and December 31, 2022	—		—
Common stock (200,000,000 shares authorized at $0.01 par value) (83,460,990 and 83,406,002 shares issued; 68,962,220 and 71,949,742 shares outstanding at June 30, 2023 and December 31, 2022)						Common stock (200,000,000 shares authorized at $0.01 par value) (83,460,990 and 83,406,002 shares issued; 68,962,220 and 71,949,742 shares outstanding at June 30, 2023 and December 31, 2022)	1		1
Treasury stock (14,498,770 shares held at cost at June 30, 2023 and 11,456,260 shares held at cost at December 31, 2022)						Treasury stock (14,498,770 shares held at cost at June 30, 2023 and 11,456,260 shares held at cost at December 31, 2022)	(584)		(461)
Additional paid-in capital	Additional paid-in capital	1,301		1,288		Additional paid-in capital	1,317		1,305
Retained earnings	Retained earnings	876		475		Retained earnings	1,295		938
Accumulated other comprehensive income	Accumulated other comprehensive income	72		72		Accumulated other comprehensive income	81		81

Total stockholders' equity	Total stockholders' equity	1,855		1,688		Total stockholders' equity	2,110		1,864
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,986	$	3,846	TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,900	$	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~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021~~2022

(dollars in millions, except share and per share data)


		Three months ended September 30,				Nine months ended September 30,					Three months ended June 30,				Six months ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
REVENUES	REVENUES									REVENUES
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	680	$	549	$	2,026	$	1,459	Oil, natural gas and NGL sales	$	447	$	718	$	1,162	$	1,346
Net gain (loss) from commodity derivatives	Net gain (loss) from commodity derivatives	243		(125)		(419)		(603)		Net gain (loss) from commodity derivatives	31		(100)		73		(662)
Sales of purchased natural gas	Sales of purchased natural gas	113		95		220		241		Sales of purchased natural gas	72		75		256		107
Electricity sales	Electricity sales	88		65		171		131		Electricity sales	34		49		102		83
Other revenue	Other revenue	1		4		27		27		Other revenue	7		5		22		26
Total operating revenues	Total operating revenues	1,125		588		2,025		1,255		Total operating revenues	591		747		1,615		900

OPERATING EXPENSES	OPERATING EXPENSES									OPERATING EXPENSES
Operating costs	Operating costs	214		190		586		523		Operating costs	186		190		440		372
General and administrative expenses	General and administrative expenses	59		51		163		147		General and administrative expenses	71		56		136		104
Depreciation, depletion and amortization	Depreciation, depletion and amortization	50		54		149		160		Depreciation, depletion and amortization	56		50		114		99
Asset impairments		—		25		2		28
Asset impairment										Asset impairment	—		2		3		2
Taxes other than on income	Taxes other than on income	44		36		120		113		Taxes other than on income	42		42		84		76
Exploration expense	Exploration expense	1		2		3		6		Exploration expense	1		1		2		2
Purchased natural gas expense	Purchased natural gas expense	98		53		186		144		Purchased natural gas expense	27		67		151		88
Electricity generation expenses	Electricity generation expenses	42		29		99		70		Electricity generation expenses	13		33		62		57
Transportation costs	Transportation costs	13		11		37		37		Transportation costs	16		12		33		24
Accretion expense	Accretion expense	10		13		32		39		Accretion expense	11		11		23		22
Other operating expenses, net	Other operating expenses, net	5		4		28		31		Other operating expenses, net	21		9		34		23
Total operating expenses	Total operating expenses	536		468		1,405		1,298		Total operating expenses	444		473		1,082		869
Net gain on asset divestitures	Net gain on asset divestitures	2		2		60		4		Net gain on asset divestitures	—		4		7		58

OPERATING INCOME (LOSS)		591		122		680		(39)
OPERATING INCOME										OPERATING INCOME	147		278		540		89

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

Interest and debt expense										Interest and debt expense	(14)		(13)		(28)		(26)

Loss from investment in unconsolidated subsidiary										Loss from investment in unconsolidated subsidiary	(1)		—		(3)		—
Other non-operating income										Other non-operating income	3		1		2		2
INCOME BEFORE INCOME TAXES										INCOME BEFORE INCOME TAXES	135		266		511		65
Income tax provision	Income tax provision	(153)		—		(203)		—		Income tax provision	(38)		(76)		(113)		(50)
NET INCOME (LOSS)		426		107		441		(89)
NET INCOME										NET INCOME	$	97	$	190	$	398	$	15

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

Net income (loss) attributable to common stock per share

Net income per share										Net income per share
Basic	Basic	$	5.75	$	1.26	$	5.77	$	(1.23)	Basic	$	1.39	$	2.48	$	5.65	$	0.19
Diluted	Diluted	$	5.58	$	1.25	$	5.62	$	(1.23)	Diluted	$	1.35	$	2.41	$	5.47	$	0.19

Weighted-average common shares outstanding	Weighted-average common shares outstanding									Weighted-average common shares outstanding
Basic	Basic	74.1		81.6		76.4		82.6		Basic	69.7		76.7		70.5		77.6
Diluted	Diluted	76.3		82.4		78.5		82.6		Diluted	71.9		78.8		72.7		79.6

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

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

For the three and ~~nine~~ sixmonths ended ~~September~~June 30, ~~2022 and 2021~~2023

(in millions)

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


	Three months ended June 30, 2023
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, March 31, 2023	$	1	$	(520)	$	1,311	$	1,219	$	81	$	2,092
Net income	—		—		—		97		—		97

Share-based compensation	—		—		7		—		—		7



Repurchases of common stock	—		(64)		—		—		—		(64)

Cash dividend ($0.2825 per share)	—		—		—		(21)		—		(21)
Shares cancelled for taxes	—		—		(1)		—		—		(1)
Balance, June 30, 2023	$	1	$	(584)	$	1,317	$	1,295	$	81	$	2,110

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


	Six months ended June 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	—		—		—		398		—		398



Share-based compensation	—		—		14		—		—		14


Repurchases of common stock	—		(123)		—		—		—		(123)


Cash dividend ($0.2825 per share)	—		—		—		(41)		—		(41)
Shares cancelled for taxes					(2)		—		—		(2)

Balance, June 30, 2023	$	1	$	(584)	$	1,317	$	1,295	$	81	$	2,110

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Stockholders' Equity

For the three and ~~nine~~six months ended ~~September~~June 30, 2022

(in millions)


		Three months ended September 30, 2022										Three months ended June 30, 2022
		Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income			Total Equity			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
Balance, March 31, 2022															Balance, March 31, 2022	$	1	$	(219)	$	1,293	$	286	$	72	$	1,433
Net income	Net income	—		—		—		426		—			426		Net income	—		—		—		190		—		190

Share-based compensation	Share-based compensation	—		—		6		—		—			6		Share-based compensation	—		—		3		—		—		3

Repurchases of common stock	Repurchases of common stock	—		(80)		—		—		—			(80)		Repurchases of common stock	—		(96)		—		—		—		(96)

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

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

Nine months ended September 30, 2022
Common Stock Treasury Stock Additional Paid-in Capital Retained Earnings Accumulated Other
Comprehensive
Income Total
Equity
Balance, December 31, 2021 $ 1 $ (148) $ 1,288 $ 475 $ 72 $ 1,688
Net income — — — 441 — 441
Share-based compensation — — 14 — — 14
Repurchases of common stock — (247) — — — (247)
Cash dividends ($0.17 per share) — — — (40) — (40)
Other — — (1) — — (1)
Balance, September 30, 2022 $ 1 $ (395) $ 1,301 $ 876 $ 72 $ 1,855


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



Share-based compensation	—		—		8		—		—		8



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


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

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

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

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

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2021~~2023 and 2022

(in millions)

Three months ended September 30, 2021
Common Stock Treasury Stock Additional Paid-in Capital Accumulated (Deficit) Accumulated Other
Comprehensive
(Loss) Income Equity Attributable to Common Stock Equity Attributable to Noncontrolling Interests Total
Equity
Balance, June 30, 2021 $ 1 $ (45) $ 1,273 $ (328) $ (8) $ 893 $ 22 $ 915
Net (loss) income — — — 103 — 103 4 107
Distributions to noncontrolling interest holders — — — — — — (19) (19)
Redemption of noncontrolling interest — — 7 — — 7 (7) —
Share-based compensation — — 4 — — 4 — 4
Repurchases of common stock — (39) — — — (39) — (39)
Issuance of common stock — — 2 — — 2 — 2
Other comprehensive income — — — — 82 82 — 82
Balance, September 30, 2021 $ 1 $ (84) $ 1,286 $ (225) $ 74 $ 1,052 $ — $ 1,052

Nine months ended September 30, 2021
Common Stock Treasury Stock Additional Paid-in Capital Accumulated (Deficit) Accumulated Other
Comprehensive
(Loss) Income Equity Attributable to Common Stock Equity Attributable to Noncontrolling Interests Total
Equity
Balance, December 31, 2020 $ 1 $ — $ 1,268 $ (123) $ (8) $ 1,138 $ 44 $ 1,182
Net (loss) income — — — (102) — (102) 13 (89)
Distributions to noncontrolling interest holders — �� — — — — (50) (50)
Redemption of noncontrolling interest — — 7 — — 7 (7) —
Share-based compensation — — 10 — — 10 — 10
Repurchases of common stock — (84) — — — (84) — (84)
Issuance of common stock — — 2 — — 2 — 2
Other — — (1) — — (1) — (1)
Other comprehensive income — — — — 82 82 — 82
Balance, September 30, 2021 $ 1 $ (84) $ 1,286 $ (225) $ 74 $ 1,052 $ — $ 1,052


	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	97	$	190	$	398	$	15
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	56		50		114		99
Deferred income tax provision	9		62		56		29
Asset impairment	—		2		3		2
Net (gain) loss from commodity derivatives	(31)		100		(73)		662
Net payments on settled commodity derivatives	(63)		(241)		(128)		(422)


Net gain on asset divestitures	—		(4)		(7)		(58)



Other non-cash charges to income, net	30		19		51		27
Changes in operating assets and liabilities, net	10		3		4		(13)
Net cash provided by operating activities	108		181		418		341

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(39)		(98)		(86)		(197)
Changes in accrued capital investments	(2)		6		(15)		9
Proceeds from asset divestitures, net	—		16		—		76
Acquisitions	(1)		—		(1)		(17)


Other, net	(2)		—		(3)		—
Net cash used in investing activities	(44)		(76)		(105)		(129)

CASH FLOW FROM FINANCING ACTIVITIES













Repurchases of common stock	(64)		(96)		(123)		(167)
Common stock dividends	(20)		(13)		(40)		(26)




Issuance of common stock	—		—		1		—
Debt amendment costs	(8)		—		(8)		—
Shares cancelled for taxes	(1)		—		(2)		—
Net cash used in financing activities	(93)		(109)		(172)		(193)
(Decrease) increase in cash and cash equivalents	(29)		(4)		141		19
Cash and cash equivalents—beginning of period	477		328		307		305
Cash and cash equivalents—end of period	$	448	$	324	$	448	$	324

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

~~Condensed Consolidated Statements of Cash Flows~~

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

~~(in millions)~~

Three months ended September 30, Nine months ended September 30,
2022 2021 2022 2021
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss) $ 426 $ 107 $ 441 $ (89)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 50 54 149 160
Deferred income tax provision 137 — 166 —
Asset impairments — 25 2 28
Net (gain) loss from commodity derivatives (243) 125 419 603
Net payments on settled commodity derivatives (182) (99) (604) (220)
Net loss on early extinguishment of debt — — — 2
Net gain on asset divestitures (2) (2) (60) (4)
Other non-cash charges to income, net 15 17 42 46
Changes in operating assets and liabilities, net 34 (45) 21 (70)
Net cash provided by operating activities 235 182 576 456
CASH FLOW FROM INVESTING ACTIVITIES
Capital investments (107) (51) (304) (128)
Changes in accrued capital investments (4) 5 5 18
Proceeds from asset divestitures, net 3 11 79 13
Acquisitions — (53) (17) (53)
Distribution related to the Carbon TerraVault JV 12 — 12 —
Capitalized joint venture transaction costs (12) — (12) —
Other (1) — (1) (1)
Net cash used in investing activities (109) (88) (238) (151)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from Revolving Credit Facility — — — 16
Repayments of Revolving Credit Facility — — — (115)
Proceeds from Senior Notes — — — 600
Debt issuance costs — — — (13)
Repayment of Second Lien Term Loan — — — (200)
Repayment of EHP Notes — — — (300)
Repurchases of common stock (80) (39) (247) (84)
Common stock dividends (13) — (39) —
Proceeds from warrants exercised — 2 — 2
Distributions paid to a noncontrolling interest holder — (19) — (50)
Issuance of common stock 1 — 1 —
Net cash used in financing activities (92) (56) (285) (144)
Increase in cash and cash equivalents 34 38 53 161
Cash and cash equivalents—beginning of period 324 151 305 28
Cash and cash equivalents—end of period $ 358 $ 189 $ 358 $ 189

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

~~CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES~~

Notes to the Condensed Consolidated Financial Statements

~~September~~June 30, ~~2022~~2023

NOTE 1 BASIS OF PRESENTATION

We are an independent ~~oil~~energy and ~~natural gas exploration and production~~carbon management company ~~operating properties exclusively within California. We are~~ committed to energy ~~transition and have~~transition. We produce some of the lowest carbon intensity ~~production~~oil in the United ~~States.~~States according to a joint report by Ceres and the Clean Air Task Force and we are focused on maximizing the value of our land, minerals and technical resources for decarbonization efforts. We are in the early stages of ~~permitting~~developing several carbon capture and storage (CCS) projects and other emissions reducing projects in California. Our subsidiary Carbon TerraVault is expected to build, install, operate and maintain CO2 capture equipment, transportation assets and storage facilities in California. In August 2022, Carbon TerraVault entered into a joint venture with BGTF Sierra Aggregator LLC (Brookfield) to pursue certain of these opportunities (Carbon TerraVault JV). See Note 2 ~~Accounting Policy and Disclosure Changes~~ ~~for our accounting policy related to joint ventures and investments~~Investment in ~~unconsolidated subsidiaries and~~ ~~Note 8 Investments~~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, our investment in 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, ~~2021 (2021~~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 63 Debt for the fair value of our debt.

109

NOTE 2 ~~ACCOUNTING POLICY~~INVESTMENT IN UNCONSOLIDATED SUBSIDIARY AND ~~DISCLOSURE CHANGES~~RELATED PARTY TRANSACTIONS

~~Accounting Policy Update~~

~~Joint Ventures~~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 ~~Investments in Unconsolidated Subsidiaries~~

Brookfield holds a 49% interest. We ~~may enter into joint ventures~~determined that ~~are considered to be~~the Carbon TerraVault JV is a variable interest entity (VIE). A VIE is a legal entity that possesses any of the following conditions: the entity's equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities; however, we share decision-making power with Brookfield on all matters that most significantly impact the ~~legal entity's~~ economic performance ~~(or they possess disproportionate voting rights in relation to~~of the ~~economic interest~~joint venture. Therefore, we account for our investment in the ~~legal entity), or~~Carbon TerraVault JV under the equity ~~owners lack~~method of accounting. Transactions between us and the ~~obligation~~Carbon TerraVault JV are related party transactions.

Brookfield has committed an initial $500 million to absorb the legal entity's expected losses or the right to receive the legal entity's expected residual returns. We consolidate a VIE if we determine that we have (i) the power to direct the activities of the VIE that most significantly impact its economic performance and (ii) the obligation to absorb losses or the right to receive benefits from the VIEinvest in CCS projects that are more than insignificant to the VIE. If an entity is determined to be a VIE but we do not have a controlling interest, the entity is accounted for under either the cost or equity method depending on whether we exercise significant influence. See ~~Note 8 Investments and Related Party Transactions~~ ~~for more information on~~jointly approved through the Carbon TerraVault JV. ~~These evaluations~~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, we used $4 million 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 ~~highly complex and involve management judgment and may involve~~not met, the ~~use of estimates and assumptions based~~initial investment by Brookfield is reflected as a contingent liability included in other long-term liabilities on ~~available information. The evaluation requires continual assessment.~~our condensed consolidated balance sheets.

~~Investments~~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 ~~unconsolidated entities are assessed for impairment whenever changes in~~an approved budget. The MSA may be terminated by mutual agreement of the ~~facts and circumstances indicate a loss in value may have occurred, which is~~parties, among other ~~than temporary.~~events.

~~Recently Adopted Accounting~~The tables below present the summarized financial information related to our equity method investment and ~~Disclosure Changes~~related party transactions for the periods presented.



	June 30,		December 31,
	2023		2022
	(in millions)
Investment in unconsolidated subsidiary(a)	$	14	$	13
Receivable from affiliate(b)	$	29	$	33
Property, plant and equipment(c)	$	2	$	—
Other long-term liabilities - Contingent liability (related to Carbon TerraVault JV put and call rights)(d)	$	50	$	48

~~ASC Topic 848,~~ (a)~~Reference Rate Reform~~ ~~contains guidance for applying U.S. GAAP~~Reflects our investment less losses allocated to ~~contracts, hedging relationships~~us of $3 million and ~~other transactions that are impacted by reference rate reform. Under this guidance, we elected to account~~$1 million for the ~~February~~six months ended June 30, 2023 and the year ended December 31, 2022, ~~amendment~~respectively.

(b)At June 30, 2023, the amount of ~~our Revolving Credit Facility described~~$29 million includes $28 million which may be distributed 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 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 ~~Note 6 Debt~~ ~~as a modification of the original instrument. The debt modification did not have a material impact to~~other long-term liabilities on our condensed consolidated ~~financial statements.~~balance sheet. Our obligation due to repurchase features related to the 26R reservoir includes $4 million and $2 million of accrued interest at June 30, 2023 and December 31, 2022, respectively.


	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Loss from investment in unconsolidated subsidiary	$	1	$	—	$	3	$	—
General and administrative expenses(a)	$	2	$	—	$	3	$	—

(a)Includes amounts recognized by us under the MSA for administrative, operational and commercial services.

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 ~~SUPPLEMENTAL BALANCE SHEET INFORMATION~~

~~Other current assets~~ ~~— Other current assets includes the following:~~

September 30, December 31,
2022 2021
(in millions)
Amounts due from joint interest partners $ 39 $ 47
Fair value of derivative contracts 64 6
Prepaid expenses 14 16
Greenhouse gas allowances 14 31
Natural gas margin deposits 5 12
Other 7 9
Other current assets $ 143 $ 121

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

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

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

September 30, December 31,
2022 2021
(in millions)
Accrued employee-related costs $ 64 $ 61
Accrued taxes other than on income 43 30
Asset retirement obligations 78 51
Accrued interest 9 19
Lease liability 12 11
Premiums due on derivative contracts 64 57
Liability for settlement payments on derivative contracts 48 25
Amounts due under production-sharing contracts 9 14
Income taxes payable 17 —
Marketing prepayments 4 5
Other 23 24
Accrued liabilities $ 371 $ 297

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

September 30, December 31,
2022 2021
(in millions)
Compensation-related liabilities $ 34 $ 38
Postretirement and pension benefit plans 54 59
Lease liability 32 37
Premiums due on derivative contracts 13 5
Contingent liability related to Carbon TerraVault JV put and call rights 46 —
Other 6 6
Other long-term liabilities $ 185 $ 145

~~NOTE 4 SUPPLEMENTAL CASH FLOW INFORMATION~~

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

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

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

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

~~NOTE 5 INVENTORIES~~

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

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

~~NOTE 6~~ DEBT

As of ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, our long-term debt consisted of the following:


		September 30,		December 31,					June 30,		December 31,
		2022		2021		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	600		600		7.125%	February 1, 2026
Principal amount	Principal amount	$	600	$	600			Principal amount	$	600	$	600
Unamortized debt issuance costs	Unamortized debt issuance costs	(9)		(11)				Unamortized debt issuance costs	(7)		(8)
Long-term debt, net	Long-term debt, net	$	591	$	589			Long-term debt, net	$	593	$	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. This~~lenders, which amends and restates in its entirety the prior credit agreement ~~currently consists~~dated October 27, 2020. As of June 30, 2023, our Revolving Credit Facility consisted of a senior revolving loan facility ~~(Revolving Credit Facility)~~ with an aggregate commitment of ~~$602~~$627 million, which ~~we are permitted to~~includes a net $25 million increase ~~if we obtain additional commitments from new or existing lenders. This amount includes $110 million~~that occurred during the second quarter of ~~additional commitments from new lenders that joined this facility in February 2022 and September 2022.~~2023. Our Revolving Credit Facility also ~~includes~~included a sub-limit of ~~$200~~$250 million for the issuance of letters of credit. ~~Letters~~As of June 30, 2023, $148 million letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

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

•extending the maturity date to July 31, 2027;

•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. 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.

The borrowing base is redetermined semi-annually and was reaffirmed at $1.2 billion on ~~October 25, 2022.~~April 26, 2023 as part of our amendment. 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.

1311

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

In April 2022, we amended our Revolving Credit Facility to, among other things, modify the minimum hedge requirement and the restricted payment and investment covenants contained in the Revolving Credit Facility. As a result of this amendment, the rolling hedge requirement as described in ~~Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt~~ in our 2021 Annual Report has been modified. As amended, our Revolving Credit Facility requires us to maintain hedges on a minimum amount of crude oil production (determined on (i) the date of delivery of annual and quarterly financial statements and (ii) the date of delivery of a reserve report delivered in connection with an interim borrowing base redetermination) of no less than (i) in the event that our Consolidated Total Net Leverage Ratio (as defined in the Credit Agreement) is greater than 2:1 as of the end of the most recent fiscal quarter test period, 50% of our reasonably anticipated oil production from our proved developed producing reserves for each quarter during the period ending the earlier of (1) the maturity date of the Revolving Credit Facility and (2) 12 months after the delivery of the compliance certificate for the relevant test period and (ii) in the event that our Consolidated Total Net Leverage Ratio is less than or equal to 2:1 but greater than 1:1 as of the end of the most recent fiscal quarter test period, 33% of our reasonably anticipated oil production from our proved developed producing reserves for each quarter during the period ending the earlier of (1) the maturity date of the Revolving Credit Facility and (2) 12 months after the delivery of the compliance certificate for the relevant test period. The foregoing minimum hedge requirements do not apply to the extent that our Consolidated Total Net Leverage Ratio is less than or equal to 1:1 as of the last day of the most recently ended fiscal quarter test period.

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

At ~~September~~June 30, ~~2022,~~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.

Fair Value

The ~~estimated~~ fair value of our fixed-rate debt at ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021~~2022 was approximately ~~$564~~$604 million and ~~$623~~$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 June 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.

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 from the volatility of commodity 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 six months ended June 30, 2023 and 2022. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to implement our hedging strategy.

Summary of open derivative contracts on oil — We held the following Brent-based contracts as of June 30, 2023:


	Q3 2023		Q4 2023		Q1 2024		Q2 2024		2H 2024		2025
Sold Calls
Barrels per day	17,363		5,747		7,750		10,500		10,375		14,811
Weighted-average price per barrel	$	57.06	$	57.06	$	90.00	$	90.20	$	90.20	$	85.83

Swaps
Barrels per day	19,697		27,094		6,000		1,000		1,000		1,687
Weighted-average price per barrel	$	70.73	$	70.73	$	79.06	$	77.20	$	77.20	$	70.32

Net Purchased Puts(a)
Barrels per day	17,363		5,747		14,684		10,500		10,375		14,811
Weighted-average price per barrel	$	76.25	$	76.25	$	69.72	$	65.48	$	65.48	$	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.

Fair value of derivatives — The following tables present the fair values on a recurring basis (at gross and net) of our outstanding commodity derivatives as of June 30, 2023 and December 31, 2022:


June 30, 2023
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
	(in millions)
Other current assets, net(a)	$	46	$	(9)	$	37
Other noncurrent assets	54		(37)		17

Current liabilities(a)	(81)		9		(72)
Noncurrent liabilities	(37)		37		—
	$	(18)	$	—	$	(18)

(a)In addition to our Brent based derivative contracts in the table above, we held swaps as of June 30, 2023 for 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 $1 million included in other current assets, net and $2 million included in current liabilities at June 30, 2023.


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 in the table above, we held swaps as of December 31, 2022 for 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.

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 six months ended June 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 tables present the components of our total income tax provision and a reconciliation of the U.S. federal statutory rate to our effective tax rate:


	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Income before income taxes	$	135	$	266	$	511	$	65

Current income tax provision	29		14		57		21
Deferred income tax provision	9		62		56		29
Total income tax provision	$	38	$	76	$	113	$	50


	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
U.S. federal statutory tax rate	21	%	21	%	21	%	21	%
State income taxes, net	7		7		7		7


Change in the valuation allowance	—		—		(6)		49
Other	—		1		—		—
Effective tax rate	28	%	29	%	22	%	77	%

During the six months ended June 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. During the six months ended June 30, 2023, we recognized the benefit of this tax loss 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

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

~~During~~In the three and ~~nine~~six months ended ~~September~~June 30, 2022, we recorded a gain of $2$4 million and ~~$12~~$10 million, respectively, related to the sale of certain Ventura basin assets. We did not close transactions during the three months ended September 30, 2022. The amount recognized in the three and nine months ended September 30, 2022 included $2 million and $6 million, respectively, of additional earn-out consideration on closings that occurred in the second half of 2021 and the first half of 2022. In addition, we also received $2 million to secure performance of well abandonment which we expect to release to the buyer once the abandonment obligations are met. As a result, we recorded a liability of $2 million included as accrued liabilities on our condensed consolidated balance sheet as of September 30, 2022. See ~~Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions~~ ~~in our 2021 Annual Report for additional information on the Ventura basin transactions.~~

The closing of the sale of our remaining assets in the Ventura basin is subject to final approval from the State Lands Commission, which we expect to receive ~~prior to~~in the ~~end of the first quarter~~second half of 2023. These remaining assets, consisting of property, plant and equipment, and associated asset retirement obligations are classified as held for sale on our condensed consolidated balance ~~sheet as of September~~sheets at June 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

~~On February 1,~~During the 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.

~~CRC Plaza~~

In June 2022, we sold our commercial office building located in Bakersfield, California for net proceeds of $13 million, recognizing no gain or loss on sale. We also leased back a portion of the building with a term of 18 months. In the second quarter of 2022, prior to the sale we recorded a $2 million impairment charge to write down the carrying value to fair value, which was determined based on a market approach (using Level 3 inputs in the fair value hierarchy).

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

Other

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

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

Acquisitions

During the ~~nine~~six months ended ~~September~~June 30, 2022, we acquired properties ~~and land easements~~ for carbon management activities for approximately $17 million. ~~There~~We are evaluating the sale of certain unwanted assets that were ~~no acquisitions for the three months ended September 30, 2022.~~

~~In August 2021, we purchased the 90% working interest held by Macquarie Infrastructure~~part of this acquisition and ~~Real Assets Inc (MIRA) in certain oil and natural gas properties~~recognized an impairment of $3 million in the ~~San Joaquin basin~~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 inflation and rising interest rates. These unwanted assets are classified as held for ~~$53 million, before purchase price adjustments and transaction costs. Refer to~~ ~~Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions~~ insale as of June 30, 2023 on our ~~2021 Annual Report for more information on the acquisition~~. ~~There were no other acquisitions for the three and nine months ended September 30, 2021.~~condensed consolidated balance sheet.

NOTE 8 ~~INVESTMENTS AND RELATED PARTY TRANSACTIONS~~STOCKHOLDERS' EQUITY

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

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

~~The Carbon TerraVault JV has an option to participate in certain projects that involve the capture, transportation and storage of CO~~2 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).Share Repurchase Program

Our ~~proportionate share~~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 ~~net loss generated by the Carbon TerraVault JV~~program at any time. The following is a summary of our share repurchases, held as treasury stock for the ~~three and nine months ended September 30, 2022 was insignificant due to the start-up nature of the joint venture.~~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 June 30, 2022	2,255,445	$	96	$	42.57
Three months ended June 30, 2023	1,618,746	$	64	$	39.12

Six months ended June 30, 2022	3,923,901	$	167	$	42.55
Six months ended June 30, 2023	3,042,510	$	123	$	40.12

Inception of Program (May 2021) through June 30, 2023	14,498,770	$	584	$	40.18

~~NOTE 9 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES~~Note: The total value of shares purchased includes approximately $1 million in the six months ended June 30, 2023 related to excise taxes on share repurchases, which was effective beginning in 2023. Commissions paid were not significant in all periods presented.

~~We accrue reserves for currently outstanding lawsuits, claims~~On February 23, 2023, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock which 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 ~~proceedings when it is probable that~~was paid on March 16, 2023. On April 28, 2023, our Board of Directors declared a ~~liability has been incurred~~quarterly cash dividend of $0.2825 per share of common stock which amounted to $20 million in the aggregate. The dividend was payable to shareholders of record at the close of business on June 1, 2023 and was paid on June 16, 2023.

Future cash dividends, and the ~~liability can be reasonably estimated. Reserve balances~~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 13 Subsequent Event for these items at September 30, 2022 and December 31, 2021 were not material to our condensed consolidated balance sheets as of such dates. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined.information on future cash dividends.

Warrants

In October 2020, ~~Signal Hill Services, Inc. defaulted on its decommissioning obligations associated with two offshore platforms. The Bureau~~we reserved an aggregate 4,384,182 shares of ~~Safety and Environmental Enforcement (BSEE) determined that former lessees, including~~ our ~~former parent, Occidental Petroleum Corporation (Oxy) with a 37.5%~~common stock for warrants which are exercisable at $36 per 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.through October 26, 2024.

~~NOTE 10 DERIVATIVES~~

~~We maintain a commodity hedging program primarily focused on crude oil~~As of June 30, 2023, we had outstanding warrants exercisable into 4,295,157 shares of our common stock (subject to ~~help protect our cash flows, margins and capital program from~~adjustments pursuant to the ~~volatility~~terms of ~~commodity prices. We did not have any derivative instruments designated as accounting hedges as of and for~~the warrants). During the three and ~~nine~~six months ended ~~September~~June 30, 2023 and 2022, ~~and 2021. Unless otherwise indicated,~~ we ~~use the term "hedge" to describe derivative instruments that are designed to achieve~~issued an insignificant amount of shares of our ~~hedging requirements and program goals.~~common stock in exchange for warrants.

~~Currently, we may not hedge more than 85% of reasonably anticipated total forecasted production of crude oil, natural gas~~See Part II, Item 8 – Financial Statements and ~~NGLs from~~Supplementary Data, Note 11 Stockholders' Equity in our ~~oil and gas properties~~2022 Annual Report for ~~a 48-month period, except that we may purchase puts and floors up to 100% of such production. The percentage~~additional information on the terms of our ~~crude oil production hedged is calculated exclusive of offsetting positions on our derivative contracts. See~~ ~~Note 6 Debt~~ ~~for more information on an amendment to our Revolving Credit Facility and our hedging requirements.~~warrants.

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

Q4
2022 Q1
2023 Q2
2023 Q3
2023 Q4
2023 2024
Sold Calls
Barrels per day 25,167 18,322 17,837 17,363 5,747 —
Weighted-average price per barrel $ 57.82 $ 57.28 $ 60.00 $ 57.06 $ 57.06 $ —
Swaps
Barrels per day 17,263 14,620 14,475 14,697 24,094 1,492
Weighted-average price per barrel $ 58.79 $ 67.36 $ 66.36 $ 66.27 $ 69.14 $ 79.06
Net Purchased Puts(a)
Barrels per day 25,167 18,322 17,837 17,363 5,747 1,724
Weighted-average price per barrel $ 64.47 $ 76.25 $ 76.25 $ 76.25 $ 76.25 $ 75.00
Sold Puts
Barrels per day 1,348 — — — — —
Weighted-average price per barrel $ 32.00 $ — $ — $ — $ — $ —

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

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

~~The outcomes of the derivative positions are as follows:~~

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

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

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

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

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

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

September 30, 2022
Classification Gross Amounts at Fair Value Netting Net Fair Value
Assets (in millions)
Other current assets - Fair value of derivative contracts $ 85 $ (21) $ 64
Other noncurrent assets - Fair value of derivative contracts 28 (3) 25
Liabilities
Current - Fair value of derivative contracts (275) 21 (254)
Noncurrent - Fair value of derivative contracts (29) 3 (26)
$ (191) $ — $ (191)

December 31, 2021
Classification Gross Amounts at Fair Value Netting Net Fair Value
Assets (in millions)
Other current assets - Fair value of derivative contracts $ 33 $ (27) $ 6
Other noncurrent assets - Fair value of derivative contracts 12 (11) 1
Liabilities
Current - Fair value of derivative contracts (297) 27 (270)
Noncurrent - Fair value of derivative contracts (143) 11 (132)
$ (395) $ — $ (395)

Our derivative contracts are measured at fair value using industry-standard models with various inputs, including quoted forward prices, and are classified as Level 2 in the required fair value hierarchy for the periods presented. We recognized fair value changes on derivative instruments each reporting period in net loss from commodity derivatives on our condensed consolidated statements of operations for the three and nine months ended September 30, 2022 and 2021. The changes in fair value result from the relationship between our existing positions, volatility, time to expiration, contract prices and the associated forward curves.

NOTE 119 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) were calculated using the treasury stock method for the three and ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021.~~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~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021:~~2022:

Three months ended September 30, Nine months ended September 30,
2022 2021 2022 2021
(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS
Net income (loss) $ 426 $ 107 $ 441 $ (89)
Less: net income attributable to noncontrolling interests
— (4) — (13)
Net income (loss) attributable to common stock $ 426 $ 103 $ 441 $ (102)
Denominator for Basic EPS
Weighted-average shares 74.1 81.6 76.4 82.6
Potential Common Shares, if dilutive:
Warrants 0.7 — 0.7 —
Restricted Stock Units 0.8 0.4 0.7 —
Performance Stock Units 0.7 0.4 0.7 —
Denominator for Diluted EPS
Weighted-average shares 76.3 82.4 78.5 82.6
EPS
Basic $ 5.75 $ 1.26 $ 5.77 $ (1.23)
Diluted $ 5.58 $ 1.25 $ 5.62 $ (1.23)

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

Three months ended September 30, Nine months ended September 30,
2022 2021 2022 2021
(in millions)
Shares issuable upon exercise of warrants(a)
— 4.3 — 4.3
Shares issuable upon settlement of RSUs — — — 0.9
Shares issuable upon settlement of PSUs — — — 0.6
Total antidilutive shares — 4.3 — 5.8

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

~~NOTE 12 PENSION AND POSTRETIREMENT BENEFIT PLANS~~

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

Three months ended September 30, Three months ended September 30,
2022 2021
Pension
Benefit Postretirement
Benefit Pension
Benefit Postretirement
Benefit
(in millions) (in millions)
Service cost - benefits earned during the period $ — $ 1 $ — $ 1
Interest cost on projected benefit obligation 1 — 1 —
Expected return on plan assets (1) — — —
Curtailment gain — — — (1)
Amortization of prior service cost credit — (2) — —
Net periodic benefit costs $ — $ (1) $ 1 $ —

Nine months ended September 30, Nine months ended September 30,
2022 2021
Pension
Benefit Postretirement
Benefit Pension
Benefit Postretirement
Benefit
(in millions) (in millions)
Service cost - benefits earned during the period $ 1 $ 2 $ 1 $ 3
Interest cost on projected benefit obligation 1 1 1 2
Expected return on plan assets (1) — (1) —
Curtailment gain — — — (1)
Amortization of prior service cost credit — (5) — —
Net periodic benefit costs $ 1 $ (2) $ 1 $ 4

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

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

~~NOTE 13 INCOME TAXES~~

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

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



	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
	(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS
Net income	$	97	$	190	$	398	$	15





Denominator for Basic EPS
Weighted-average shares	69.7		76.7		70.5		77.6

Potential Common Shares, if dilutive:
Warrants	0.5		0.7		0.5		0.7
Restricted Stock Units	0.9		0.7		0.9		0.7
Performance Stock Units	0.8		0.7		0.8		0.6

Denominator for Diluted EPS
Weighted-average shares	71.9		78.8		72.7		79.6

EPS
Basic	$	1.39	$	2.48	$	5.65	$	0.19
Diluted	$	1.35	$	2.41	$	5.47	$	0.19

NOTE ~~14 STOCKHOLDERS' EQUITY~~

~~Share Repurchase Program~~10 SUPPLEMENTAL ACCOUNT BALANCES

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $650 million of our common stock through June 30, 2023. As of September 30, 2022, we have repurchased an aggregate 9,935,070 shares of our common stock for $395 million, at an average price of $39.74 per share, since inception of the Share Repurchase Program in May 2021.The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time. See ~~Note 16 Subsequent Events~~Revenues ~~for information on an increase and extension to our Share Repurchase Program.~~

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

~~Shares repurchased were held as treasury stock as of September 30, 2022.~~

~~Dividends~~

On February 23, 2022, our Board of Directors declared a quarterly cash dividend of $0.17 per share of common stock. The dividend was payable to shareholders of record at the close of business on March 7, 2022 and $13 million was paid on March 16, 2022. On May 4, 2022, our Board of Directors declared a quarterly cash dividend of $0.17 per share of common stock. The dividend was payable to shareholders of record at the close of business on June 1, 2022 and $13 million was paid on June 16, 2022. On August 3, 2022, our Board of Directors declared a quarterly cash dividend of $0.17 per share of common stock. The dividend was payable to shareholders of record at the close of business on September 1, 2022 and $13 million was paid on September 16, 2022.

Future cash dividends, and the establishment of record and payment dates, are subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. See ~~Note 16 Subsequent Events~~ ~~for information on future cash dividends.~~

~~Warrants~~

We reserved an aggregate 4,384,182 shares of our common stock for warrants which are exercisable at $36 per share through October 26, 2024. As of September 30, 2022, we had outstanding warrants exercisable into 4,295,434 shares of our common stock (subject to adjustments pursuant to the terms of the warrants).

The Warrant Agreement contains customary anti-dilution adjustments in the event of any stock split, reverse stock split, stock dividend and certain other distributions. The warrant holder may elect, in its sole discretion, to pay cash or to exercise on a cashless basis, pursuant to which the holder will not be required to pay cash for shares of common stock upon exercise of the warrant but will instead receive fewer shares. See ~~Part II, Item 8 – Financial Statements and Supplementary Data, Note 10 Equity~~ ~~in our 2021 Annual Report for a description of our warrants and~~ ~~Note 14 Chapter 11 Proceedings~~ ~~for more information on the issuance of these warrants pursuant to our joint plan of reorganization.~~

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

~~Employee Stock Purchase Plan~~

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

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

~~BSP JV~~

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

~~NOTE 15 REVENUE RECOGNITION~~

— We derive most of our revenue from sales of oil, natural gas and ~~NGLs,~~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,					Three months ended June 30,				Six months ended June 30,
		2022		2021			2022		2021				2023		2022		2023		2022
		(in millions)									(in millions)
Oil	Oil	$	494	$	413		$	1,527	$	1,124		Oil	$	362	$	547	$	752	$	1,033
Natural gas	Natural gas	120		69			294		161			Natural gas	43		94		306		174
NGLs	NGLs	66		67			205		174			NGLs	42		77		104		139
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	680	$	549		$	2,026	$	1,459		Oil, natural gas and NGL sales	$	447	$	718	$	1,162	$	1,346

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



	June 30,		December 31,
	2023		2022
	(in millions)
Materials and supplies	$	65	$	56
Finished goods	4		4
Inventories	$	69	$	60

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



	June 30,		December 31,
	2023		2022
	(in millions)
Net amounts due from joint interest partners(a)	$	32	$	39

Fair value of commodity derivative contracts	37		39
Prepaid expenses	21		17
Greenhouse gas allowances	16		—
Natural gas margin deposits	3		16
Income tax receivable	4		10
Other	12		12
Other current assets, net	$	125	$	133

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

Other noncurrent assets — Other noncurrent assets include the following:



	June 30,		December 31,
	2023		2022
	(in millions)
Operating lease right-of-use assets	$	83	$	73
Deferred financing costs - Revolving Credit Facility	12		6
Emission reduction credits	11		11
Prepaid power plant maintenance	31		28
Fair value of commodity derivative contracts	17		7
Deposits and other	12		15
Other noncurrent assets	$	166	$	140

2218

Accrued liabilities — Accrued liabilities include the following:


	June 30,		December 31,
	2023		2022
	(in millions)
Employee-related costs	$	65	$	49
Taxes other than on income	31		32
Asset retirement obligations	72		59
Interest	19		19
Operating lease liability	16		18

Premiums due on commodity derivative contracts	35		58
Liability for settlement payments on commodity derivative contracts	15		33
Amounts due under production-sharing contracts	7		—
Signal Hill maintenance	11		8


Other	28		22
Accrued liabilities	$	299	$	298

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



	June 30,		December 31,
	2023		2022
	(in millions)
Compensation-related liabilities	$	40	$	36
Postretirement benefit plan	29		33
Operating lease liability	64		52

Premiums due on commodity derivative contracts	13		8
Contingent liability (related to Carbon TerraVault JV put and call rights)	50		48
Other	8		8
Other long-term liabilities	$	204	$	185

General and administrative expenses — 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 are net of amounts invoiced under the MSA to the Carbon TerraVault JV. See Note 2 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV.

G&A expenses were $71 million for the three months ended June 30, 2023, which was an increase of $15 million from $56 million for the three months ended June 30, 2022. G&A expenses were $136 million for the six months ended June 30, 2023, which was an increase of $32 million from $104 million for the six months ended June 30, 2022. The increase in G&A expenses for the three and six month periods was primarily attributable to compensation-related expenses, including accelerated vesting for certain departing employees and stock-based compensation awards granted in 2023, and higher spending on information technology infrastructure.


	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Exploration and production, corporate and other	$	68	$	52	$	130	$	99
Carbon management business	3		4		6		5
Total general and administrative expenses	$	71	$	56	$	136	$	104

Other operating expenses, net — 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 includes lease cost for carbon sequestration easements, advocacy, and other startup related costs.


	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Exploration and production, corporate and other	$	13	$	9	$	22	$	23
Carbon management business	8		—		12		—
Total other operating expenses, net	$	21	$	9	$	34	$	23

NOTE 11 SUPPLEMENTAL CASH FLOW INFORMATION

We paid $51 million of U.S. federal and state income tax payments during the three and six months ended June 30, 2023. We paid $20 million of U.S. federal income tax payments during the three and six months ended June 30, 2022. No state income tax payments were made in the three and six months ended June 30, 2022.

Interest paid, net of capitalized amounts, was insignificant for the three months ended June 30, 2023 and $22 million for the six months ended June 30, 2023. Interest paid, net of capitalized amounts, was insignificant for the three months ended June 30, 2022 and $22 million for the six months ended June 30, 2022.

Non-cash investing activities in the three and six months ended June 30, 2023 included $2 million and $4 million, respectively, related to our share of capital calls by the Carbon TerraVault JV. See Note 2 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV. Non-cash investing activities in the three and six months ended June 30, 2022 included $1 million of additional earn-out consideration related to our Ventura basin asset divestiture.

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 June 30, 2023 and December 31, 2022 and the condensed consolidating statements of operations for the three and six months ended June 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 June 30, 2023 and December 31, 2022


	As of June 30, 2023
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
	(in millions)
Total current assets	$	467	$	30	$	370	$	—	$	867
Total property, plant and equipment, net	12		7		2,726		—		2,745
Investments in consolidated subsidiaries	2,736		(9)		1,530		(4,257)		—
Deferred tax asset	108		—		—		—		108
Investment in unconsolidated subsidiary	—		14		—		—		14
Other assets	14		42		110		—		166
TOTAL ASSETS	$	3,337	$	84	$	4,736	$	(4,257)	$	3,900

Total current liabilities	95		9		478		—		$	582
Long-term debt	593		—		—		—		593
Asset retirement obligations	—		—		411		—		411
Other long-term liabilities	77		76		51		—		204
Amounts due to (from) affiliates	462		21		(483)		—		—
Total equity	2,110		(22)		4,279		(4,257)		2,110
TOTAL LIABILITIES AND EQUITY	$	3,337	$	84	$	4,736	$	(4,257)	$	3,900


	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 six months ended June 30, 2023 and 2022


	Three months ended June 30, 2023
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
	(in millions)
Total revenues	$	5	$	—	$	586	$	—	$	591
Total costs and other	62		11		371		—		444

Non-operating (loss) income	(11)		(2)		1		—		(12)
(LOSS) INCOME BEFORE INCOME TAXES	(68)		(13)		216		—		135
Income tax provision	(38)		—		—		—		(38)
NET (LOSS) INCOME	$	(106)	$	(13)	$	216	$	—	$	97


	Three months ended June 30, 2022
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
	(in millions)
Total revenues	$	—	$	—	$	747	$	—	$	747
Total costs and other	43		5		425		—		473
Gain on asset divestitures	—		—		4		—		4
Non-operating (loss) income	(13)		—		1		—		(12)
(LOSS) INCOME BEFORE INCOME TAXES	(56)		(5)		327		—		266
Income tax provision	(76)		—		—		—		(76)
NET (LOSS) INCOME	$	(132)	$	(5)	$	327	$	—	$	190


	Six months ended June 30, 2023
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
	(in millions)
Total revenues	$	9	$	—	$	1,606	$	—	$	1,615
Total costs and other	112		19		951		—		1,082
Gain on asset divestitures	—		—		7		—		7
Non-operating (loss) income	(27)		(5)		3		—		(29)
(LOSS) INCOME BEFORE INCOME TAXES	(130)		(24)		665		—		511
Income tax provision	(113)		—		—		—		(113)
NET (LOSS) INCOME	$	(243)	$	(24)	$	665	$	—	$	398


	Six months ended June 30, 2022
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
	(in millions)
Total revenues	$	—	$	—	$	900	$	—	$	900
Total costs and other	81		7		781		—		869
Gain on asset divestitures	—		—		58		—		58
Non-operating (loss) income	(27)		—		3		—		(24)
(LOSS) INCOME BEFORE INCOME TAXES	(108)		(7)		180		—		65
Income tax provision	(50)		—		—		—		(50)
NET (LOSS) INCOME	$	(158)	$	(7)	$	180	$	—	$	15

NOTE 1613 SUBSEQUENT ~~EVENTS~~

~~Dividends~~EVENT

On November 2, 2022, our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of $1.13, payable to shareholders in quarterly increments of $0.2825 per share of common stock. The actual declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. Also on November 2, 2022,July 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 ~~December~~September 1, ~~2022~~2023 and is expected to be paid on ~~December 16, 2022.~~September 15, 2023.

~~Share Repurchase Program~~

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

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

General

We are an independent ~~oil~~energy and ~~natural gas exploration and production~~carbon management company operating properties exclusively within California. We provide ample, affordable and reliable energy in a safe and responsible manner, to support and enhance the quality of life of Californians and the local communities in which we operate. We do this through the development of our broad portfolio of assets while adhering to our commitment to make value-based capital investments. Further, we are committed to energy ~~transition and have~~transition. We produce some of the lowest carbon intensity ~~production~~oil in the United ~~States.~~

~~Through~~States according to a joint report by Ceres and the Clean Air Task Force and we are focused on maximizing the value of our ~~subsidiary, Carbon TerraVault, we~~land, minerals and technical resources for decarbonization efforts. We are in the early stages of developing several carbon capture and storage (CCS) projects and other emissions reducing projects in California. We intend to pursue some or all of these projects through our Carbon TerraVault JV ~~described below. Currently,~~that we have applied for permits for two initial permanent CCS projects at the Elk Hills Field. In May 2022, we applied for permits for an additional 80 MMT of carbon storage, which once approved, will increase our total potential permitted storage to 120 MMT. We are targeting filing additional carbon storage permits before the end of 2022, which, once approved, would increase our total permitted storage to 140 MMT to be utilized in carbon capture and storage projects. Separately, we are evaluating the feasibility of a carbon capture system to be located at our Elk Hills power plant for CCS. A new front-end engineering design (FEED) study to explore the application of proprietary post-combustion capture and compression of up to 95% of the COformed 2with BGTF Sierra Aggregator LLC (Brookfield) ~~emissions from the Elk Hills power plant is ongoing. We are also pursuing multiple solar projects for supplying the grid (front-of-the-meter solar) and powering our operations (behind-the-meter solar)~~.

While all of these projects are in early stages, we expect that the size and scope of our projects providing these and similar services and capital spent on such projects will continue to grow given our strategy of expansion into ~~these services.~~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, ~~2021 (2021~~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.

~~Carbon TerraVault Joint Venture~~

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

~~Dividends~~

In 2021, our Board of Directors approved a cash dividend policy which anticipates a total annual dividend of $0.68 per share of common stock, payable in quarterly increments of $0.17 per share of common stock. On November 2, 2022, our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of $1.13, payable to shareholders in quarterly increments of $0.2825 per share of common stock. The actual declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. Also on November 2, 2022, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend is payable to shareholders of record at the close of business on December 1, 2022 and is expected to be paid on December 16, 2022. The aggregate payment for this quarterly dividend is approximately $20 million.

~~Share Repurchase Program~~

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $650 million of our common stock through June 30, 2023. On November 2, 2022, our Board of Directors increased the Share Repurchase Program by $200 million to $850 million from $650 million and extended the program through December 31, 2023. As of October 31, 2022, we have repurchased an aggregate 10,617,862 shares of our common stock for $424 million, at an average price of $39.89 per share, since the inception of the Share Repurchase Program in May 2021. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time.

~~Shares repurchased are held as treasury stock. See~~ ~~Part I, Item 1 – Financial Statements, Note 14 Stockholders' Equity~~ ~~for more information on our share repurchase activity during the three and nine months ended September 30, 2022.~~

~~Divestitures and Acquisitions~~

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

Business Environment and Industry Outlook

Commodity Prices

Our operating results and those of the oil and 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 ~~increased~~declined slightly in the ~~first nine~~three months ~~of 2022~~ended June 30, 2023 compared to the same period in 2021 due to Russia's invasion of Ukraine and following boycotts of Russian oil and sanctions imposed on Russia by the United States and other countries, increasing demand from the remaining world producers of oil. Global oil prices were also positively impactedthree months ended March 31, 2023 as demand outpaced supply as COVID-19 restrictions eased. Currently, global oil inventories are low relative to historical levels and supply from OPEC+ and other oil producing nations are not expected to be sufficient to meet forecasted oil demand growth for the next few years. It is believed that many OPEC+ countries will be unable to increase their production levels or even produce at expected levels due to their lack of capital investments in developing incremental oil supplies over the past few years. In October 2022, OPEC+ determined to reduce production beginning in November 2022 through December 2023 by 2 million barrels per day, due to the uncertainty surrounding the global economic and oil market outlooks. In the United States, natural gas prices were influenced by increased domestic demand, global demand for oil remained generally flat. The decrease in natural gas inindex prices during the ~~form of liquified~~three months ended June 30, 2023 compared to the three months ended March 31, 2023 occurred as North American natural gas ~~exports as a result of the Russia-Ukraine conflict~~production and ~~concerns over low inventories. Brent crude oil prices have declined from the~~storage inventories remained relatively high ~~experienced~~ in the second ~~quarter of 2022~~quarter. Refer to Prices and ~~could decline further due to, among other things, a prolonged high inflationary environment,~~Realizations below for additional releases from the U.S. Strategic Petroleum Reserve or a recession. Although the forward strip prices for the next twelve months remain high relative to commodity prices in recent years, the current commodity price environment remains uncertain. The extent to which commodity prices andinformation our operating and financial results of future periods will be impacted by the ongoing conflict in Ukraine, increasing inflation, government efforts to reduce inflation, any recession, the COVID-19 pandemic and the actions of foreign oil and gas producers will depend largely on future developments, which are highly uncertain and cannot be accurately predicted.realized prices.

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

Three months ended Nine months ended
September 30, 2022 June 30, 2022 September 30, 2022 September 30, 2021
Brent oil ($/Bbl) $ 97.81 $ 111.79 $ 102.33 $ 67.78
WTI oil ($/Bbl) $ 91.56 $ 108.41 $ 98.09 $ 64.82
NYMEX Henry Hub ($/MMBtu) Contract Month Average $ 7.85 $ 6.62 $ 6.22�� $ 3.06
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price $ 8.20 $ 7.17 $ 6.77 $ 3.18

~~Supply Chain and Cost Inflation~~

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


	Three months ended				Six months ended
	June 30, 2023		March 31, 2023		June 30, 2023		June 30, 2022
Brent oil ($/Bbl)	$	78.01	$	82.22	$	80.12	$	104.59
WTI oil ($/Bbl)	$	73.78	$	76.13	$	74.95	$	101.35
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	$	2.10	$	3.42	$	2.76	$	6.06

2624

Regulatory Updates

~~Kern County Environmental Impact Report~~

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 ~~currently requires an operator~~for our operations. A variety of factors outside of our control can lead to ~~identify the manner in which the California Environmental Quality Act (CEQA)~~such delays. Since December 2022, CalGEM has been satisfied prior to issuing various state permits, typically through either an environmental review or an exemption by a state or local agency. In Kern County, this requirement has typically been satisfied by complying with the local oil and gas ordinance which was supported by an Environmental Impact Report (EIR) certified by the Kern County Board of Supervisors in 2015.

~~A group of petitioners challenged the EIR and on February 25, 2020, a California Appellate Court (the Court)~~ issued a ~~ruling that required Kern County~~limited number of permits for new production wells in California, and those permits were issued to ~~decertify the EIR~~other operators. We continue to receive permits from CalGEM for workovers, deepenings, sidetracks and ~~set aside the amended Zoning Ordinance. In response, Kern County prepared, circulated~~plugging and ~~certified a supplementary recirculated EIR (Supplemental EIR) to address the ruling from the Court~~abandonment operations. For more information, see Part I, Item 1 & 2 – Business and in April 2021, resumed issuing local permits relying on the Supplemental EIR. However, on October 22, 2021, Kern County was ordered to cease reviewing and approving oil and gas permits until the trial court determined that the Zoning Ordinance complies with CEQA requirements. On May 26, 2022, a hearing was held in Kern County and the Court ruled that Kern County’s local permitting system must cease until the trial court verified that the noted deficiencies had been remedied and that the remedies satisfied the concerns raised by the Court. In October 2022, the trial court ruled that the Supplemental EIR was not decertified but ordered Kern County to address four discrete issues before suspensionProperties, Regulation of the local permitting could be lifted, which, once resolved, would bring the Supplemental EIR into compliance with applicable laws. The four discrete issues included requirements for the removal of offsite legacy equipment to mitigate agricultural land use impacts, revising emission reduction requirements to address particulate matter, the establishment of a drinking water grant fund for disadvantaged communitiesIndustries in ~~Kern County, and updating the local oil and gas ordinance to reflect these requirements. The Kern County Board of Supervisors approved these changes~~Which We Operate in ~~August 2022. On October 12,~~our 2022 Kern County submitted notice with the trial court of these changes and on November 2, 2022 the trial court lifted the order preventing reliance on the local permitting system. This ruling is subject to further appeal by the petitioners and there is still some potential for future disruptions to obtaining permits in Kern County until any such appeals are resolved.

~~Carbon Capture, Sequestration and Storage –California Program Management~~Annual Report.

~~On September 16, 2022,~~Our operations in the ~~Governor~~Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. These operations are subject to regulation by the City of ~~California signed Senate Bill No. 905 into law, which contemplates~~Long Beach and CalGEM. We are currently in discussions with the ~~development~~City of ~~unitization, permitting~~Long Beach and ~~pipeline safety regulations~~CalGEM with respect to what injection well pressure gradient complies with CalGEM’s regulatory requirements for the protection of underground sources of drinking water, while at the same time mitigating subsidence risks. 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. As part of our ongoing discussions, we and the City of Long Beach have provided CalGEM with technical information regarding how the historical injection well pressure gradient complies with CalGEM's requirements, as well as the Clean Water Act, and to inform them of the absence of risk of leakage from the injection zone. CalGEM has proposed a meeting for CRC and the City of Long Beach to present their technical findings in more detail, to occur in or around August 2023. As part of that meeting, and subject to its outcome, CalGEM has also proposed that CRC and the City of Long Beach present a work plan for the reduction of injection pressures over a ~~multi-year~~six-month period to ~~facilitate~~levels acceptable to CalGEM. We are in the ~~development~~process of ~~CCS projects in California. We believe our Carbon TerraVault projects, for which permits with the EPA have been filed, will~~preparing a response and continue to ~~be developed~~believe that existing injection pressures address subsidence risks and are protective of underground sources of drinking water. If CalGEM were to ultimately disagree and determine to reduce the injection well pressure gradient, and we were unable to reverse that decision on appeal or other legal challenge, we expect any material reduction in injection well pressure gradient for our operations in the Wilmington Oil Field would result in a timeline consistent with our initial expectations. These initial projects are not reliant on the unitization or permitting regulations being developed. In addition, our Carbon TerraVault projects are expected to either use emitters that are directly sited above these storage facilities or rely on pipelines for transporting CO2 ~~that will need to comply with yet to be developed CO~~2 ~~pipeline safety regulations~~decrease in production and reserves from the ~~federal Pipeline~~field. For additional information, see Part I, Item 1 & 2 – Business and ~~Hazardous Materials Safety Administration. Delays~~Properties, Regulation of the Industries in ~~developing required pipeline safety regulations would~~Which We Operate, Regulation of Exploration and Production Activities and the Risk factor entitled "Our business is highly regulated and government authorities can delay ~~projects requiring pipeline transportation of CO~~2.

~~The unified permitting process contemplated by Senate Bill No. 905 will be optional for project applicants~~or deny permits and ~~is intended to simplify the permitting process for CCS projects. In the meantime, pursuant to this legislation we are permitted to proceed with~~approvals or change requirements governing our ~~existing~~operations, including hydraulic fracturing and ~~future permit applications with the EPA. This law also contemplates~~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 ~~a new regulatory program incorporating standards that are not yet defined and that could affect the timing of future CCS projects~~our business plans" in ~~California.~~

~~Senate Bill No. 905 also prohibits projects that utilize and permanently sequester CO~~2 in connection with EOR projects. These projects had the potential to create incremental net zero carbon oil production that displaces higher carbon intensity foreign imports. In light of this prohibition and the enhancement of energy credits under the Inflation Reduction Act ofour 2022 ~~(the Act), we will transition our CalCapture project to target CCS.~~Annual Report.

~~We do not have any existing oil~~

Supply Chain Constraints and ~~gas production, and only have contingent resources, associated with EOR projects that rely on CO~~2 ~~floods. As a result, we do not expect the limitations on EOR activities included in Senate Bill No. 905 to impact our existing oil and gas production or proved reserves.~~

Inflation

~~Oil~~In 2023, we have experienced relatively flat pricing compared to 2022. Labor costs and ~~Gas Operations – Health Protection Zones~~national electricity prices have risen which has partially negated the benefits of supply chains opening up in 2023. Further, we have been unable to obtain price reductions from our vendors for certain purchased goods, including OCTG, wellbore tubulars and chemicals. These categories have raw material inputs such as steel and diesel fuel which have experienced intermediate price spikes throughout the first half of 2023 preventing our vendors from offering price reductions for these items.

~~On September 16, 2022,~~We have taken measures to limit the ~~Governor~~effects of ~~California signed Senate Bill No. 1137~~inflation by entering into ~~law, which establishes 3,200 feet as the minimum distance between new oil~~contracts for materials and ~~gas production wells and certain sensitive receptors such as homes, schools or parks effective January 1, 2023. This law also imposes health, safety and environmental controls applicable~~services with terms of one to both current and new wells located within this distance of sensitive receptors related to noise, light, and dust pollution controls and air emission monitoring, as well as providing for the immediate suspension of operations at production facilities determined to not be in compliance with certain air emission requirements, among other matters. The latter provisions are effective January 1, 2025.

~~The majority of our production is in rural areas~~three years. For contracts that we anticipate renegotiating in the ~~San Joaquin basin~~second half of 2023, we expect moderate price increases for certain purchased goods and ~~is unlikely~~services. We also continue to ~~be affected by Senate Bill No. 1137. We are evaluating the impact on~~look at ways to improve productivity and performance from our ~~remaining assets, including our Wilmington and Huntington Beach fields in the LA Basin~~workforce and our natural gas fields in the Sacramento Basin. Certain proved undeveloped and proved developed non-producing reserves associated with projects would be impacted by this legislation; however, we may accelerate other substitute projects within the five-year period associated with our proved reserves. We do not expect this law to result in any change in our existing proved developed producing reserves or current production rates or any material change to the timing of plugging and abandonment liabilities. As a result of this law, our development plans will change but we do not currently expect an impairment of our assets or that our overall pace of development to be affected materially.

~~Inflation Reduction Act~~

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

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

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

2825

Production

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


		Three months ended		Nine months ended		Three months ended				Six months ended
		September 30, 2022	June 30, 2022		September 30, 2022		September 30, 2021		June 30, 2023	March 31, 2023	June 30, 2023	June 30, 2022
Oil (MBbl/d)	Oil (MBbl/d)							Oil (MBbl/d)
San Joaquin Basin	San Joaquin Basin	36	38		37		39	San Joaquin Basin	34	35	35	38
Los Angeles Basin	Los Angeles Basin	19	16		18		19	Los Angeles Basin	19	20	19	17
Ventura Basin		—	—		—		3

Total	Total	55	54		55		61	Total	53	55	54	55
NGLs (MBbl/d)	NGLs (MBbl/d)							NGLs (MBbl/d)
San Joaquin Basin	San Joaquin Basin	12	12		11		13	San Joaquin Basin	11	11	11	11

Total	Total	12	12		11		13	Total	11	11	11	11
Natural gas (MMcf/d)	Natural gas (MMcf/d)							Natural gas (MMcf/d)
San Joaquin Basin	San Joaquin Basin	131	132		128		135	San Joaquin Basin	119	119	119	127
Los Angeles Basin	Los Angeles Basin	1	1		1		1	Los Angeles Basin	1	1	1	1
Ventura Basin		—	—		—		5

Sacramento Basin	Sacramento Basin	17	18		18		19	Sacramento Basin	15	16	16	18
Total	Total	149	151		147		160	Total	135	136	136	146

Total Net Production (MBoe/d)	Total Net Production (MBoe/d)	92	91		91		101	Total Net Production (MBoe/d)	86	89	88	90

Total daily net production for the three months ended ~~September~~June 30, ~~2022,~~2023, compared to the three months ended ~~June 30, 2022 increased~~March 31, 2023 decreased by ~~approximately 1~~3 MBoe/d ~~or 1%.~~largely due to natural decline and changes in NGL storage volumes. This increase is predominately a result of our production-sharing contracts (PSCs), which positively impacted our net oil production in the three months ended September 30, 2022 by approximately 2 MBoe/d, compared to the three months ended June 30, 2022. This increasedecrease was partially offset by ~~natural decline.~~

~~Total daily net~~increased production for the nine months ended September 30, 2022, compared to the same period in 2021, decreased by approximately 10 MBoe/d, or 10%. The decrease in production reflects the divestiture of our remaining 50% working interest in certain zones in the Lost Hills field in February 2022from drilling and the divestiture of certain assets in our Ventura basin operations which began in the fourth quarter of 2021. Divestitures reduced our total net production by approximately 5 MBoe/d for the nine months ended September 30, 2022 compared to the prior year period. The decrease also resulted from planned maintenance at one of our cryogenic gas processing facilities in the first quarter of 2022 as well as natural decline. These decreases were partially offset by improved operational results from our developmental drilling program and our acquisition of the working interests in certain joint venture wells held by Macquarie Infrastructure and Real Assets Inc. (MIRA) in the third quarter of 2021.workover activity. Our ~~PSCs,~~production-sharing contracts (PSCs), which are described below, negatively impacted our net oil production by 1 MBoe/d in the ~~nine~~three months ended ~~September~~June 30, ~~2022 by approximately 1 MBoe/d,~~2023 compared to the three months ended March 31, 2023.

Total daily net production for the six months ended June 30, 2023, compared to the same prior year period decreased by 2 MBoe/d largely due to natural decline partially offset by increased production from drilling and workover activity. Our PSCs positively impacted our production by 2 MBoe/d in ~~2021.~~the six months ended June 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		Six months ended
	June 30, 2023	March 31, 2023	June 30, 2023	June 30, 2022
	(MBoe/d)
Total Net Production	86	89	88	90
Partners' share under PSC-type contracts	7	6	6	7
Working interest and royalty holders' share	8	7	8	8
Changes in NGL inventory and other	2	1	1	1
Total Gross Production	103	103	103	106

2926

Production-Sharing Contracts (PSCs)

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of production and reserves to recover a portion of such capital, operating and abandonment costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital, operating and abandonment costs that we incur on their behalf, (ii) for our share of contractually defined base production and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and operating costs. However, our net economic benefit is greater when product prices are higher. These contracts represented approximately 16% of our net production for both the three and nine months ended September 30, 2022.

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

The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. Operating costs, excluding effects of PSC-type contracts is a non-GAAP measure which adjusts for excess costs attributable to PSC-type contracts for the periods presented in the tables below:


		Three months ended								Three months ended
		September 30, 2022				June 30, 2022					June 30, 2023				March 31, 2023
		(in millions)		($ per Boe)		(in millions)		($ per Boe)					(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs	Operating costs	$	214	$	25.27	$	190	$	22.92			Operating costs	$	186	$	23.71	$	254	$	31.61
Excess costs attributable to PSC-type contracts	Excess costs attributable to PSC-type contracts	(18)		$	(2.16)	(21)		$	(2.58)			Excess costs attributable to PSC-type contracts	(17)		$	(2.15)	(18)		$	(2.23)
Operating costs, excluding effects of PSC-type contracts	Operating costs, excluding effects of PSC-type contracts	$	196	$	23.11	$	169	$	20.34			Operating costs, excluding effects of PSC-type contracts	$	169	$	21.56	$	236	$	29.38


		Nine months ended									Six months ended
		September 30, 2022				September 30, 2021					June 30, 2023				June 30, 2022
		(in millions)		($ per Boe)		(in millions)		($ per Boe)			(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs	Operating costs	$	586	$	23.71	$	523	$	19.04	Operating costs	$	440	$	27.71	$	372	$	22.90
Excess costs attributable to PSC-type contracts	Excess costs attributable to PSC-type contracts	(58)		$	(2.35)	(47)		$	(1.72)	Excess costs attributable to PSC-type contracts	(35)		$	(2.19)	(40)		$	(2.45)
Operating costs, excluding effects of PSC-type contracts	Operating costs, excluding effects of PSC-type contracts	$	528	$	21.36	$	476	$	17.32	Operating costs, excluding effects of PSC-type contracts	$	405	$	25.52	$	332	$	20.45

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.

3027

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

Three months ended Nine months ended
September 30, 2022 June 30, 2022 September 30, 2022 September 30, 2021
(MBoe/d)
Total Net Production 92 91 91 101
Partners' share under PSC-type contracts 7 8 8 7
Working interest and royalty holders' share 7 8 7 9
Other 1 1 1 1
Total Gross Production 107 108 107 118

Prices and Realizations

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


		Three months ended						Three months ended
		September 30, 2022			June 30, 2022				June 30, 2023				March 31, 2023
		Price		Realization	Price		Realization				Price		Realization	Price		Realization
Oil ($ per Bbl)	Oil ($ per Bbl)									Oil ($ per Bbl)
Brent	Brent	$	97.81		$	111.79				Brent	$	78.01		$	82.22

Realized price without derivative settlements	Realized price without derivative settlements	$	97.96	100%	$	112.32	100%			Realized price without derivative settlements	$	75.77	97%	$	78.68	96%
Effects of derivative settlements		(35.51)			(49.15)
Derivative settlements										Derivative settlements	(12.11)			(15.64)
Realized price with derivative settlements	Realized price with derivative settlements	$	62.45	64%	$	63.17	57%			Realized price with derivative settlements	$	63.66	82%	$	63.04	77%

WTI	WTI	$	91.56		$	108.41				WTI	$	73.78		$	76.13

Realized price without derivative settlements	Realized price without derivative settlements	$	97.96	107%	$	112.32	104%			Realized price without derivative settlements	$	75.77	103%	$	78.68	103%
Realized price with derivative settlements	Realized price with derivative settlements	$	62.45	68%	$	63.17	58%			Realized price with derivative settlements	$	63.66	86%	$	63.04	83%

NGLs ($ per Bbl)	NGLs ($ per Bbl)									NGLs ($ per Bbl)
Realized price (% of Brent)	Realized price (% of Brent)	$	57.68	59%	$	68.29	61%			Realized price (% of Brent)	$	42.48	54%	$	58.88	72%
Realized price (% of WTI)	Realized price (% of WTI)	$	57.68	63%	$	68.29	63%			Realized price (% of WTI)	$	42.48	58%	$	58.88	77%

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

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

NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	8.20		$	7.17				NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	2.10		$	3.42

Realized price without derivative settlements ($/Mcf)	Realized price without derivative settlements ($/Mcf)	$	8.80	107%	$	6.85	96%			Realized price without derivative settlements ($/Mcf)	$	3.46	165%	$	21.56	630%
Effects of derivative settlements		(0.22)			(0.13)
Derivative settlements										Derivative settlements	—			—
Realized price with derivative settlements ($/Mcf)	Realized price with derivative settlements ($/Mcf)	$	8.58	105%	$	6.72	94%			Realized price with derivative settlements ($/Mcf)	$	3.46	165%	$	21.56	630%

3128


		Nine months ended							Six months ended
		September 30, 2022			September 30, 2021				June 30, 2023			June 30, 2022
		Price		Realization	Price		Realization		Price		Realization	Price		Realization
Oil ($ per Bbl)	Oil ($ per Bbl)							Oil ($ per Bbl)
Brent	Brent	$	102.33		$	67.78		Brent	$	80.12		$	104.59

Realized price without derivative settlements	Realized price without derivative settlements	$	102.01	100%	$	67.62	100%	Realized price without derivative settlements	$	77.25	96%	$	104.07	100%
Effects of derivative settlements		(40.05)			(13.19)
Derivative settlements								Derivative settlements	(13.90)			(42.36)
Realized price with derivative settlements	Realized price with derivative settlements	$	61.96	61%	$	54.43	80%	Realized price with derivative settlements	$	63.35	79%	$	61.71	59%

WTI	WTI	$	98.09		$	64.82		WTI	$	74.95		$	101.35

Realized price without derivative settlements	Realized price without derivative settlements	$	102.01	104%	$	67.62	104%	Realized price without derivative settlements	$	77.25	103%	$	104.07	103%
Realized price with derivative settlements	Realized price with derivative settlements	$	61.96	63%	$	54.43	84%	Realized price with derivative settlements	$	63.35	85%	$	61.71	61%

NGLs ($ per Bbl)	NGLs ($ per Bbl)							NGLs ($ per Bbl)
Realized price (% of Brent)	Realized price (% of Brent)	$	66.98	65%	$	49.20	73%	Realized price (% of Brent)	$	50.88	64%	$	72.57	69%
Realized price (% of WTI)	Realized price (% of WTI)	$	66.98	68%	$	49.20	76%	Realized price (% of WTI)	$	50.88	68%	$	72.57	72%

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

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

NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	6.77		$	3.18		NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	2.76		$	6.06

Realized price without derivative settlements ($/Mcf)	Realized price without derivative settlements ($/Mcf)	$	7.33	108%	$	3.67	115%	Realized price without derivative settlements ($/Mcf)	$	12.44	451%	$	6.58	109%
Effects of derivative settlements		(0.12)			(0.03)
Derivative settlements								Derivative settlements	—			(0.07)
Realized price with derivative settlements ($/Mcf)	Realized price with derivative settlements ($/Mcf)	$	7.21	106%	$	3.64	114%	Realized price with derivative settlements ($/Mcf)	$	12.44	451%	$	6.51	107%

Oil — Brent prices decreased slightly for the three months ended ~~September~~June 30, ~~2022~~2023 compared to the three months ended March 31, 2023 as global demand for crude remained generally flat. Oil prices in the six months ended June 30, ~~2022 due to slowing global economic activity and ongoing releases from the U.S. Strategic Petroleum Reserve. Prices increased for the nine months ended September 30, 2022 compared to~~2023 were lower than the same ~~prior-year~~prior year period in 2022 as ~~the effects of the COVID-19 pandemic have subsided leaving~~global energy inventories (including crude, ~~oil production~~refined products and ~~product inventories at low levels. Producers have generally maintained capital discipline, OPEC+ members have failed~~natural gas) stabilized and as Russian crude and refined products continue to ~~produce at stepped-up quotas, and the conflict between Russia and Ukraine has created disconnects between traditional buyers and sellers of Russian-produced crude oil.~~reach markets.

NGLs — NGL prices for the three months ended ~~September~~June 30, ~~2022~~2023 decreased compared to the three months ended ~~June 30, 2022~~March 31, 2023 reflecting traditional seasonality in NGL pricing, as ~~a result~~well as higher than normal levels of ~~incremental North American production and seasonal demand.~~inventory for this time of year. NGL prices for the ~~nine~~six months ended ~~September~~June 30, ~~2022 increased~~2023 decreased compared to the ~~nine months ended September 30, 2021~~same prior year period as ~~NGL markets benefited from higher energy~~prices for competing and ~~fuel prices, as~~complementary products (natural gas, crude oil) have declined. For both periods, California remained a ~~whole.~~premium market compared to other North American locations.

Natural Gas — Our realized price for natural gas ~~increased~~decreased for the three ~~and nine~~ months ended ~~September~~June 30, ~~2022 as~~2023 compared to the three months ended March 31, 2023 as weather across the West Coast of the United States during the quarter remained moderate and as California storage inventories rebounded from historically low levels. Natural gas prices in the six months ended June 30, 2023 were higher than the same period in 2022 ~~and nine months ended September 30, 2021 primarily due to strong domestic demand for power generation~~reflecting the unprecedented pricing experienced in California natural gas markets during the ~~summer and the need to refill storage ahead~~first quarter of ~~the upcoming heating season. Storage volumes in the beginning of 2022 were lower than the prior year, which led to increased demand to replenish inventories before the winter months.~~2023.

3229

Statements of Operations Analysis

Results of Oil and Gas Operations

In November 2020, the SEC amended Regulation S-K to, among other things, provide companies with the option to discuss material changes to results of operations between the current and immediately preceding quarter. Beginning in the first quarter of 2022, we elected to discuss our results of operations on a sequential-quarter basis. We believe this approach provides more meaningful and useful information to measure our performance from the immediately preceding quarter. In accordance with this final rule, we are not required to include a comparison of the current quarter and the same prior-year quarter.

The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses, on a per Boe basis for the three months ended ~~September 30, 2022 and~~ June 30, ~~2022~~2023 and March 31, 2023 and the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021.~~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. Purchased natural gas used to generate steam in our steamfloods was reclassified from non-energy operating costs to energy operating costs beginning in the third quarter of 2022. All prior periods have been updated to conform to this presentation.


		Three months ended				Nine months ended			Three months ended						Six months ended
		September 30, 2022		June 30, 2022			September 30, 2022			September 30, 2021			June 30, 2023		March 31, 2023		June 30, 2023		June 30, 2022
		($ per Boe)							($ per Boe)
Energy operating costs	Energy operating costs	$	10.96	$	9.33		$	9.83		$	6.68	Energy operating costs	$	7.39	$	15.56	$	11.52	$	9.24
Gas processing costs	Gas processing costs	$	0.49	$	0.54		$	0.53		$	0.59	Gas processing costs	$	0.64	$	0.62	$	0.63	$	0.55
Non-energy operating costs	Non-energy operating costs	$	13.82	$	13.05		$	13.35		$	11.77	Non-energy operating costs	$	15.68	$	15.43	$	15.56	$	13.11
Operating costs	Operating costs	$	25.27	$	22.92		$	23.71		$	19.04	Operating costs	$	23.71	$	31.61	$	27.71	$	22.90

Field general and administrative expenses(a)	Field general and administrative expenses(a)	$	1.18	$	0.84		$	1.01		$	0.87	Field general and administrative expenses(a)	$	1.40	$	1.49	$	1.45	$	0.92
Field depreciation, depletion and amortization(b)	Field depreciation, depletion and amortization(b)	$	5.31	$	5.43		$	5.30		$	5.21	Field depreciation, depletion and amortization(b)	$	6.50	$	6.72	$	6.61	$	5.29
Field taxes other than on income	Field taxes other than on income	$	3.66	$	3.62		$	3.36		$	3.02	Field taxes other than on income	$	3.70	$	3.73	$	3.72	$	3.20

a.Excludes unallocated general and administrative expenses.

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

Operating costs ~~for the three months ended September 30, 2022 were higher than~~decreased during the three months ended June 30, ~~2022 on both a total and per Boe basis~~2023 compared to the three months ended March 31, 2023 primarily due to lower energy operating costs as ~~a result of higher electricity and~~ natural gas prices ~~(increasing~~in California markets declined between quarters. Operating costs were higher in the six months ended June 30, 2023 compared to the same prior year period primarily due to increased energy operating ~~costs) and downhole maintenance activity (increasing non-energy operating costs). Operating~~ costs ~~in the nine months ended September 30, 2022 were higher than the same period in 2021 primarily~~ as ~~a result of higher~~ natural gas ~~and electricity prices.~~prices in California experienced unprecedented highs during the first quarter of 2023. Lower production volumes ~~in 2022~~ also contributed to the increase on a per Boe basis. We expect non-energy operating costs related to repair and maintenance activities to increase during the remainder of 2022 and 2023 as inflationary pressures increase costs for services, labor and supplies.

Field ~~taxes other than on income for the three months ended September 30, 2022 were consistent with~~depreciation, depletion and amortization decreased slightly during the three months ended June 30, ~~2022. Field taxes other than on income for~~2023 compared to the ~~nine~~three months ended ~~September 30, 2022 were also consistent with the same period in 2021, but higher on a per Boe basis~~March 31, 2023 due to lower production ~~volumes in 2022.~~volumes. Field ~~taxes other than income for~~depreciation, depletion and amortization increased during the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to the same prior year period ~~were lower for ad valorem taxes~~primarily due to a change in our depreciation, depletion and amortization rates which are periodically adjusted to reflect current reserve estimates. This increase was partially offset by ~~increased~~lower production ~~taxes and higher greenhouse gas taxes due~~volumes in the six months ended June 30, 2023 compared to ~~emission levels as we increased activity and market prices.~~the six months ended June 30, 2022. Lower production volumes also contributed to the increase on a per Boe basis.

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 ~~September~~June 30, ~~2022~~2023 compared to ~~June 30, 2022~~March 31, 2023

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


		Three months ended					Three months ended
		September 30, 2022		June 30, 2022			June 30, 2023		March 31, 2023
		(in millions)					(in millions)
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	680	$	718	Oil, natural gas and NGL sales	$	447	$	715
Net gain (loss) from commodity derivatives		243		(100)
Net gain from commodity derivatives						Net gain from commodity derivatives	31		42
Sales of purchased natural gas	Sales of purchased natural gas	113		75		Sales of purchased natural gas	72		184
Electricity sales	Electricity sales	88		49		Electricity sales	34		68
Other revenue	Other revenue	1		5		Other revenue	7		15
Total operating revenues	Total operating revenues	$	1,125	$	747	Total operating revenues	$	591	$	1,024

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were ~~$680 million for the three months ended September 30, 2022, which is a decrease of $38 million compared to $718~~$447 million for the three months ended June 30, ~~2022.~~2023, which is a decrease of $268 million compared to $715 million for the three months ended March 31, 2023. This decrease was primarily due to lower realized prices for ~~oil and NGLs. This decrease was partially offset by increased oil production and higher realized prices for natural gas.~~the second quarter of 2023 as shown in the table below.


		Oil		NGLs		Natural Gas		Total			Oil		NGLs		Natural Gas		Total
		(in millions)									(in millions)
Three months ended June 30, 2022		$	547	$	77	$	94	$	718
Three months ended March 31, 2023										Three months ended March 31, 2023	$	390	$	62	$	263	$	715
Changes in realized prices	Changes in realized prices	(70)		(12)		26		(56)		Changes in realized prices	(15)		(18)		(221)		(254)
Changes in production	Changes in production	17		1		—		18		Changes in production	(13)		(2)		1		(14)
Three months ended September 30, 2022		$	494	$	66	$	120	$	680
Three months ended June 30, 2023										Three months ended June 30, 2023	$	362	$	42	$	43	$	447

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

The effect of cash settlements on our commodity derivative contracts is not included in the table above. Payments on commodity derivatives were ~~$182 million for the three months ended September 30, 2022 compared to payments of $241~~$63 million for the three months ended June 30, ~~2022.~~2023 compared to $65 million for the three months ended March 31, 2023. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales ~~increased~~decreased by ~~$21~~$266 million ~~or 4%~~ compared to the three months ended ~~June 30, 2022.~~March 31, 2023.

Net gain ~~(loss)~~ from commodity derivatives — Net gain from commodity derivatives was ~~$243 million for the three months ended September 30, 2022 compared to a net loss of $100~~$31 million for the three months ended June 30, ~~2022.~~2023 compared to $42 million for the three months ended March 31, 2023. The change primarily resulted from non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period as well as the relationship between contract prices and the associated forward ~~curves as shown in the table below:~~curves:


		Three months ended					Three months ended
		September 30, 2022		June 30, 2022			June 30, 2023		March 31, 2023
		(in millions)					(in millions)
Non-cash commodity derivative gain	Non-cash commodity derivative gain	$	425	$	141	Non-cash commodity derivative gain	$	94	$	107

Net cash payments on settled commodity derivatives	Net cash payments on settled commodity derivatives	(182)		(241)		Net cash payments on settled commodity derivatives	(63)		(65)

Net gain (loss) from commodity derivatives		$	243	$	(100)
Net gain from commodity derivatives						Net gain from commodity derivatives	$	31	$	42

Sales of purchased natural gas — Sales of purchased natural gas relates to natural gas acquired from third parties which is subsequently sold in connection with certain of our marketing activities. Sales of purchased natural gas were ~~$113~~$72 million for the three months ended ~~September~~June 30, ~~2022, an increase~~2023, a decrease of ~~$38~~$112 million ~~or 51%~~ from ~~$75~~$184 million during the three months ended ~~June 30, 2022.~~March 31, 2023. The ~~increase~~decrease was primarily the result of ~~higher~~lower market prices for natural ~~gas prices.~~gas. Our natural gas sales net of related purchased natural gas expense were ~~$15 million for the three months ended September 30, 2022 compared to $8~~$45 million for the three months ended June 30, ~~2022.~~2023 compared to $60 million for the three months ended March 31, 2023.

3431

Electricity sales — Electricity sales ~~increased~~decreased by ~~$39~~$34 million to ~~$88 million for the three months ended September 30, 2022 compared to $49~~$34 million for the three months ended June 30, ~~2022. The increase was primarily~~2023 compared to $68 million for the three months ended March 31, 2023 predominately due to higher ~~natural gas~~power prices ~~and demand for electricity in~~during the ~~summer months.~~first quarter of 2023.

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


		Three months ended					Three months ended
		September 30, 2022		June 30, 2022			June 30, 2023		March 31, 2023
		(in millions)					(in millions)
Operating expenses	Operating expenses					Operating expenses
Energy operating costs	Energy operating costs	$	93	$	77	Energy operating costs	$	58	$	125
Gas processing costs	Gas processing costs	4		4		Gas processing costs	5		5
Non-energy operating costs	Non-energy operating costs	117		109		Non-energy operating costs	123		124
General and administrative expenses	General and administrative expenses	59		56		General and administrative expenses	71		65
Depreciation, depletion and amortization	Depreciation, depletion and amortization	50		50		Depreciation, depletion and amortization	56		58
Asset impairments		—		2
Asset impairment						Asset impairment	—		3
Taxes other than on income	Taxes other than on income	44		42		Taxes other than on income	42		42
Exploration expense	Exploration expense	1		1		Exploration expense	1		1
Purchased natural gas expense	Purchased natural gas expense	98		67		Purchased natural gas expense	27		124
Electricity generation expenses	Electricity generation expenses	42		33		Electricity generation expenses	13		49
Transportation costs	Transportation costs	13		12		Transportation costs	16		17
Accretion expense	Accretion expense	10		11		Accretion expense	11		12
Other operating expenses, net	Other operating expenses, net	5		9		Other operating expenses, net	21		13
Total operating expenses	Total operating expenses	536		473		Total operating expenses	444		638
Gain on asset divestitures	Gain on asset divestitures	2		4		Gain on asset divestitures	—		7
Operating income	Operating income	591		278		Operating income	147		393

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

Interest and debt expense, net		(13)		(13)
Interest and debt expense						Interest and debt expense	(14)		(14)

Other non-operating expenses, net		1		1
Loss from investment in unconsolidated subsidiary						Loss from investment in unconsolidated subsidiary	(1)		(2)
Other non-operating (expense) income						Other non-operating (expense) income	3		(1)
Income before income taxes	Income before income taxes	579		266		Income before income taxes	135		376
Income tax provision	Income tax provision	(153)		(76)		Income tax provision	(38)		(75)
Net income	Net income	$	426	$	190	Net income	$	97	$	301

Energy operating costs — Energy operating costs for the three months ended ~~September~~June 30, ~~2022~~2023 were ~~$93~~$58 million, which was ~~an increase~~a decrease of ~~$16~~$67 million ~~or 21%~~ from ~~$77~~$125 million for the three months ended ~~June 30, 2022.~~March 31, 2023. This ~~increase~~decrease was ~~predominantly~~ a result of ~~higher prices for purchased~~lower natural gas ~~which we used to generate electricity for~~prices in the second quarter of 2023. For more information on our ~~operations, steam for our steamfloods~~natural gas market prices, see Prices and ~~purchased electricity.~~Realizations above.

Non-energy operating costs — Non-energy operating costs includes $3 million and $1 million of stock-based compensation expense related to our cash-settled awards for the three months ended ~~September~~June 30, ~~2022~~2023 and March 31, 2023, 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 ~~$117 million, which was an increase of $8 million or 7% from $109~~$71 million for the three months ended June 30, ~~2022. This~~2023, which was an increase of $6 million from $65 million for the three months ended March 31, 2023. The increase in G&A expenses was primarily attributable to compensation-related expenses including accelerated vesting for certain departing employees and new stock-based compensation awards granted. Stock-based compensation awards are discussed further below.

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
	June 30, 2023		March 31, 2023
	(in millions)
Exploration and production, corporate and other	$	68	$	62
Carbon management business	3		3
Total general and administrative expenses	$	71	$	65

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 ~~result~~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.

Changes in our stock price introduce volatility in our results of ~~increased downhole maintenance activity.~~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
	June 30, 2023		March 31, 2023
	(in millions)
Cash-settled awards	$	5	$	3
Stock-settled awards	8		6
Total included in general and administrative expenses	$	13	$	9

Purchased natural gas expense — Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. We purchased ~~$98~~$27 million of natural gas for marketing activities during the three months ended ~~September~~June 30, ~~2022,~~2023, which was ~~an increase~~a decrease of ~~$31~~$97 million ~~or 46%~~ from ~~$67~~$124 million for the three months ended March 31, 2023. The decrease was predominantly the result of a decline in marketing activity and lower market prices in the three months ended June 30, 2023 compared to the three months ended March 31, 2023. For more information on our natural gas market prices, see Prices and Realizations above.

Electricity generation expenses — Electricity generation expenses for the three months ended June 30, ~~2022. The increase~~2023 were $13 million, which was ~~predominantly the result~~a decrease of ~~higher prices in~~$36 million from $49 million for the three months ended ~~September 30, 2022 compared~~March 31, 2023. This decrease was primarily due to ~~the three months ended June 30, 2022.~~lower prices for natural gas.

Income taxes – The income tax provision for the three months ended ~~September~~June 30, ~~2022~~2023 was ~~$153~~$38 million (effective tax rate of ~~26%~~28%), compared to ~~$76~~$75 million (effective tax rate of ~~29%~~20%) for the three months ended ~~June 30, 2022. The~~March 31, 2023. Excluding the effect of the change in valuation allowance, our effective tax rate ~~decreased~~would have been 28% in the three months ended ~~September 30, 2022 compared~~March 31, 2023. See Part I, Item 1 – Financial Statements, Note 6 Income Taxes for more information on a valuation allowance related to ~~the three~~our Lost Hills divestiture.

Six months ended June 30, ~~2022 due to the benefit of federal tax credits.~~

~~Nine months ended September 30, 2022~~2023 compared to ~~September~~June 30, ~~2021~~2022

The following table presents our operating revenues for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021:~~2022:


		Nine months ended September 30,					Six months ended
		2022		2021			June 30, 2023		June 30, 2022
		(in millions)					(in millions)
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	2,026	$	1,459	Oil, natural gas and NGL sales	$	1,162	$	1,346
Net loss from commodity derivatives		(419)		(603)
Net gain (loss) from commodity derivatives						Net gain (loss) from commodity derivatives	73		(662)
Sales of purchased natural gas	Sales of purchased natural gas	220		241		Sales of purchased natural gas	256		107
Electricity sales	Electricity sales	171		131		Electricity sales	102		83
Other revenue	Other revenue	27		27		Other revenue	22		26
Total operating revenues	Total operating revenues	$	2,025	$	1,255	Total operating revenues	$	1,615	$	900

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were ~~$2,026~~$1,162 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, which is ~~an increase~~a decrease of ~~$567~~$184 million compared to ~~$1,459~~$1,346 million for the ~~same period of 2021.~~six months ended June 30, 2022. This ~~increase~~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 ~~which was partially offset by lower production, as reflected in the following table:~~for natural gas.


		Oil		NGLs		Natural Gas		Total			Oil		NGLs		Natural Gas		Total
		(in millions)									(in millions)
Nine months ended September 30, 2021		$	1,124	$	174	$	161	$	1,459
Six months ended June 30, 2022										Six months ended June 30, 2022	$	1,033	$	139	$	174	$	1,346
Changes in realized prices	Changes in realized prices	572		63		160		795		Changes in realized prices	(266)		(42)		155		(153)
Changes in production	Changes in production	(169)		(32)		(27)		(228)		Changes in production	(15)		7		(23)		(31)
Nine months ended September 30, 2022		$	1,527	$	205	$	294	$	2,026
Six months ended June 30, 2023										Six months ended June 30, 2023	$	752	$	104	$	306	$	1,162

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

The effect of cash settlements on our commodity derivative contracts is not included in the table above. Payments on commodity derivatives were ~~$604~~$128 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to payments of ~~$220~~$422 million for the ~~same period of 2021.~~six months ended June 30, 2022. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by ~~$183~~$110 million ~~or 15% for the nine months ended September 30, 2022~~ compared to the ~~same prior-year period.~~six months ended June 30, 2022.

Net ~~loss~~gain (loss) from commodity derivatives — Net ~~loss~~gain from commodity derivatives was ~~$419~~$73 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to a net loss of ~~$603~~$662 million for the ~~same prior year period.~~six months ended June 30, 2022. The ~~decrease in the net loss~~change primarily resulted from non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period as well as the relationship between contract prices and the associated forward ~~curves, as shown in the table below:~~curves:


		Nine months ended September 30,					Six months ended
		2022		2021			June 30, 2023		June 30, 2022
		(in millions)					(in millions)
Non-cash commodity derivative gain (loss)	Non-cash commodity derivative gain (loss)	$	185	$	(383)	Non-cash commodity derivative gain (loss)	$	201	$	(240)

Net cash payments on settled commodity derivatives	Net cash payments on settled commodity derivatives	(604)		(220)		Net cash payments on settled commodity derivatives	(128)		(422)

Net loss from commodity derivatives		$	(419)	$	(603)
Net gain (loss) from commodity derivatives						Net gain (loss) from commodity derivatives	$	73	$	(662)

Sales of purchased natural gas — Sales of purchased natural gas relates to natural gas acquired from third parties which is subsequently sold in connection with certain of our marketing activities. Sales of purchased natural gas were ~~$220~~$256 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022, a decrease~~2023, an increase of ~~$21~~$149 million ~~or 9%~~ from ~~$241~~$107 million during the ~~same period of 2021.~~six months ended June 30, 2022. The ~~decrease~~increase was ~~predominantly~~primarily the result of ~~lower volumes, partially offset by generally~~ higher ~~prices.~~marketing activity and higher market prices in 2023. Our natural gas sales net of related purchased natural gas expense ~~was $34~~were $105 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to ~~$97~~$19 million for the ~~same period of 2021.~~six months ended June 30, 2022.

Electricity sales — Electricity sales increased by ~~$40~~$19 million to ~~$171~~$102 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to ~~$131~~$83 million for the ~~same prior-year period.~~six months ended June 30, 2022. The increase was ~~predominantly due~~predominately a result of higher power prices in the first quarter of 2023 compared to ~~higher~~the prior year. Our electricity ~~prices associated with higher natural gas prices.~~sales net of electricity generation expenses were $40 million for the six months ended June 30, 2023 compared to $26 million for the six months ended June 30, 2022.

The following table presents our operating and non-operating expenses and income for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021:~~2022:

Nine months ended
September 30,
2022 2021
(in millions)
Operating expenses
Energy operating costs $ 243 $ 184
Gas processing costs 13 16
Non-energy operating costs 330 323
General and administrative expenses 163 147
Depreciation, depletion and amortization 149 160
Asset impairments 2 28
Taxes other than on income 120 113
Exploration expense 3 6
Purchased natural gas expense 186 144
Electricity generation expenses 99 70
Transportation costs 37 37
Accretion expense 32 39
Other operating expenses, net 28 31
Total operating expenses 1,405 1,298
Net gain on asset divestitures 60 4
Operating income (loss) 680 (39)
Non-operating (expenses) income
Reorganization items, net — (5)
Interest and debt expense, net (39) (40)
Net loss on early extinguishment of debt — (2)
Other non-operating expenses, net 3 (3)
Income (loss) before income taxes 644 (89)
Income tax provision (203) —
Net income (loss) $ 441 $ (89)


	Six months ended
	June 30, 2023		June 30, 2022
	(in millions)
Operating expenses
Energy operating costs	$	183	$	150
Gas processing costs	10		9
Non-energy operating costs	247		213
General and administrative expenses	136		104
Depreciation, depletion and amortization	114		99
Asset impairment	3		2
Taxes other than on income	84		76
Exploration expense	2		2
Purchased natural gas expense	151		88
Electricity generation expenses	62		57
Transportation costs	33		24
Accretion expense	23		22
Other operating expenses, net	34		23
Total operating expenses	1,082		869
Gain (loss) on asset divestitures	7		58
Operating income	540		89

Non-operating (expenses) income

Interest and debt expense	(28)		(26)

Loss from investment in unconsolidated subsidiary	(3)		—
Other non-operating (expense) income	2		2
Income before income taxes	511		65
Income tax provision	(113)		(50)
Net income	$	398	$	15

Energy operating costs — Energy operating costs for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 were ~~$243~~$183 million, which was an increase of ~~$59~~$33 million ~~or 32%~~ from ~~$184~~$150 million for the ~~same period of 2021.~~six months ended June 30, 2022. This increase was ~~predominantly~~ a result of higher prices ~~for purchased~~in the first six months of 2023 compared to the same prior year period. For more information on our natural gas ~~which we used to generate electricity for our operations, steam for our steamfloods~~market prices, see Prices and ~~for purchased electricity.~~Realizations above.

Non-energy operating costs — Non-energy operating costs were $247 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022 were $330 million,~~2023, which was an increase of $7$34 million ~~or 2%~~ from ~~$323~~$213 million for the ~~same period of 2021. This~~six months ended June 30, 2022. The increase was ~~primarily~~predominately a result of ~~increased surface and~~higher downhole maintenance ~~activity in~~activity. Non-energy operating costs also includes $4 million and $2 million of stock-based compensation expense related to our cash-settled awards for the ~~nine~~six months ended ~~September~~June 30, 2023 and 2022, ~~compared to the same prior year period.~~respectively. See General and administrative expenses below for additional information on our stock-based compensation awards.

3735

General and administrative expenses — General and administrative (G&A) expenses ~~increased $16 million to $163~~were $136 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022 compared to $147~~2023, which was an increase of $32 million from $104 million for the ~~nine~~six months ended ~~September~~June 30, ~~2021 as a result of increased~~2022. The increase in G&A expenses was primarily attributable to compensation-related expenses, including stock-based compensation awards granted in 2023, and ~~additional headcount related~~higher spending on 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 ~~developing~~unallocated corporate overhead and other) separately from our carbon management business. The amounts shown for our carbon management business asdo not include expenses borne by the Carbon TerraVault JV.


	Six months ended
	June 30, 2023		June 30, 2022
	(in millions)
Exploration and production, corporate and other	$	130	$	99
Carbon management business	6		5
Total general and administrative expenses	$	136	$	104

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.

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.~~below:

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


	Six months ended
	June 30, 2023		June 30, 2022
	(in millions)
Cash-settled awards	$	8	$	4
Stock-settled awards	14		8
Total included in general and administrative expenses	$	22	$	12

Depreciation, depletion and amortization— Depreciation, depletion and amortization ~~decreased $11~~(DD&A) increased $15 million to ~~$149~~$114 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 from ~~$160~~$99 million for the ~~same prior year period.~~six months ended June 30, 2022. The ~~decrease~~increase was primarily ~~the result of our divestiture of our Ventura basin assets in the fourth quarter of 2021. more information on our asset divestitures, see~~ ~~Part I, Item 1 – Financial Information, Note 7 Divestitures and Acquisitions~~ ~~and~~ ~~Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions~~ due to a change in our ~~2021 Annual Report~~.

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

Purchased natural gas expense — Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. We purchased ~~$186~~$151 million of natural gas for marketing activities during the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, which was an increase of ~~$42~~$63 million ~~or 29%~~ from ~~$144~~$88 million for the ~~same prior year period.~~six months ended June 30, 2022. The increase was predominantly the result of ~~generally~~ higher marketing activity levels and higher market prices in the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to ~~2021.~~

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

~~Net gain on asset divestitures~~ – Net gain on asset divestitures for the nine months ended September 30, 2022 of $60 million primarily relates to the sale of our 50% non-operated working interest in certain horizons within our Lost Hills field and certain Ventura basin assets.2022. For more information on our ~~asset divestitures,~~natural gas market prices, see ~~Part I, Item 1 – Financial Information, Note 7 Divestitures~~Prices and ~~Acquisitions~~ Realizations~~and~~ ~~Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions~~ ~~in our 2021 Annual Report~~. above.

Income taxes – The income tax provision for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 was ~~$203~~$113 million (effective tax rate of ~~32%~~22%), ~~which includes a $31~~compared to $50 million ~~charge~~(effective tax rate of 77%) for the six months ended June 30, 2022. The income tax provision for the six months ended June 30, 2022 included a valuation allowance ~~recorded in the first quarter of 2022 at the time of~~related to our Lost Hills ~~divestiture.~~divestiture that was released in the six months ended June 30, 2023. See Part I, Item 1 – Financial Statements, Note 136 Income Taxesfor more ~~information. Realization of our deferred tax assets is subjective and remains dependent~~information on a number of factors including our ability to generate sufficient taxable income, including capital gains, in future periods. We did not recognize an income tax benefit in the nine months ended September 30, 2021 due to a full valuation allowance ~~against~~related to our ~~net deferred tax assets at that time.~~Lost Hills divestiture.

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Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity and capital resources are cash flows from operations, cash ~~on hand~~and cash equivalents and available borrowing capacity under our Revolving Credit ~~Facility which matures in April 2024.~~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~~six months ended ~~September~~June 30, ~~2022~~2023 were for capital investments, repurchases of our common stock and dividends.

The following table summarizes our liquidity:



	~~September~~June 30, ~~2022~~2023
	(in millions)
Cash and cash equivalents	$	~~358~~448
Revolving Credit Facility:
Borrowing capacity	~~602~~627
Outstanding letters of credit	~~(141)~~(148)
Availability	$	~~461~~479

Liquidity	$	~~819~~927

~~On October 25, 2022, the borrowing base under~~In April 2023 we amended our Revolving Credit Facility and our borrowing base was reaffirmed at $1.2 billion. The aggregate commitment from our lenders under our Revolving Credit Facility increased to $602 million at September 30, 2022 from $492 million at December 31, 2021 due to additional commitments from new lenders that joined this facility. See Part I, Item 1 – Financial Statements, Note 63 Debt for more information on ~~amendments~~the amendment to our Revolving Credit Facility.

At current commodity prices and based upon our planned ~~2022~~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 six months ended June 30, 2023, our operating cash flow increased $77 million, to $418 million from $341 million in the same period in 2022. The increases in operating cash flow for the six months ended June 30, 2023 primarily relates to higher average realized natural gas prices (increasing sales revenue from the natural gas we produce and margins on our marketing and trading activities) 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:



	Six months ended June 30,
		2023		2022
		(in millions)
Capital investments		$	(86)	$	(197)
Changes in accrued capital investments		(15)		9
Proceeds from divestitures, net		—		76
Acquisitions		(1)		(17)


Other, net		(3)		—
Net cash used in investing activities		$	(105)	$	(129)

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


	Six months ended June 30,
		2023		2022
		(in millions)




Repurchases of common stock		$	(123)	$	(167)
Common stock dividends		(40)		(26)

Issuance of common stock		1		$	—
Debt amendment costs		(8)		$	—
Shares cancelled for taxes		(2)		$	—
Net cash used in financing activities		$	(172)	$	(193)

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 and $245 million under current conditions with heavier weighting in the second half of the year due to timing of projects and higher expected workover activity and facilities projects. We expect our capital program related to oil and natural gas development to continue to be focused primarily on executing projects using existing permits outside of Kern County.

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	Six months ended June 30, 2023
	(in millions)
Oil and natural gas operations	$165 - $195	$	75
Carbon management business	5 - 15	1
Corporate and other	30 - 35	10
Total Capital	$200 - $245	$	86

We recently amended and extended our Revolving Credit Facility as described in Part I, Item 1 – Financial Statements, Note 3 Debt, 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.

Derivatives

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

Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended ~~September~~June 30, ~~2022.~~2023. See Part I, Item 1 – Financial Statements, Note 105 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of ~~September~~June 30, ~~2022~~2023 and Part I, II,Item 18 – Financial Statements and Supplementary Data, Note 64 Debtin our 2022 Annual Report for information ~~for more information~~ on ~~an amendment to~~ the hedging requirements included in our Revolving Credit Facility.

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~~2022 Capital~~Dividends

On April 28, 2023, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend was payable to shareholders of record at the close of business on June 1, 2023 and was paid on June 16, 2023.

On July 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 September 1, 2023 and is expected to be paid on September 15, 2023.

The 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.

Share Repurchase Program

Our ~~capital~~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 total value of shares that may yet be purchased under the Share Repurchase Program totaled $517

million, excluding commissions and excise taxes on repurchases, as of June 30, 2023. The following is ~~dynamic in response to oil market volatility while focusing on oil production and strong liquidity and maximizing~~a summary of our ~~free cash flow. We entered~~share repurchases, held as treasury stock for the fourth quarter of 2022 with four drilling rigs. We plan to average three drilling rigs during the quarter in the Huntington Beach, Buena Vista, Elk Hills and Wilmington fields as we reposition for our 2023 program.periods presented:

~~We expect our 2022 capital program to range between $380~~


	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 June 30, 2022	2,255,445	$	96	$	42.57
Three months ended June 30, 2023	1,618,746	$	64	$	39.12

Six months ended June 30, 2022	3,923,901	$	167	$	42.55
Six months ended June 30, 2023	3,042,510	$	123	$	40.12

Inception of Program (May 2021) through June 30, 2023	14,498,770	$	584	$	40.18

Note: The total value of shares purchased includes approximately $1 million ~~to $400 million. We have and will likely continue to experience cost increases~~in the six months ended June 30, 2023 related to our drilling program due to inflationary pressures, including for items such as oilfield tubular goods (tubing, casing and pipe), fuel and drilling services. We increased our 2022 capital program during the year for inflation and these cost increases could also impact our capital programexcise taxes on share repurchases, which was effective beginning in ~~2023 and beyond.~~2023. Commissions paid were not significant in all periods presented.

~~Any curtailment of the development of our properties for regulatory or operational reasons will lead to a decline in our production~~

Divestitures and ~~may lower our reserves. A continued decline in our production and reserves would negatively impact our cash flow from operations and the value of our assets.~~Acquisitions

This level of expected spending is consistent with our capital allocation strategy. Following entry into the Carbon TerraVault JV with Brookfield, we anticipate that Brookfield will fund a portion of the operating cash flow that we would have otherwise provided for advancing decarbonization and other emission reducing projects. As a result, this portion of operating cash flow will now be available for other corporate purposes, such as shareholder returns and other strategic opportunities. See ~~a summary of our Business Strategy in~~ ~~Part I, Item 1 & 2 – Business and Properties, in our 2021 Annual Report and more details on our joint venture with Brookfield in~~ Part I, Item 1 – Financial Statements, Note ~~8 Investments~~7 Divestitures and ~~Related Party Transactions~~.

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


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

~~Total Capital~~	~~$380 - $400~~	$	~~304~~

~~Cash Flow Analysis~~

~~Cash flows from operating activities~~Acquisitions ~~— For~~for information on our transactions during the ~~nine~~three and six months ended ~~September~~June 30, 2022, our operating cash flow increased 26%, or $120 million, to $576 million from $456 million in the same prior period of 2021. The increases in operating cash flow for the nine months ended September 30, 2022 primarily relates to higher average realized prices (including the effects of settlements on our commodity derivatives) in 2022 compared to the same prior-year period. This increase was partially offset by lower production volumes in 2022 as compared to the same period in 2021. The increase in our revenue was partially offset by an increase in operating costs primarily related to higher prices for purchased natural gas2023 and ~~electricity used in our operations.~~2022.

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

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

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

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

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

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

Nine months ended
September 30,
2022 2021
(in millions)
Debt transactions, net $ — $ (12)
Distributions paid to a noncontrolling interest holder — (50)
Repurchases of common stock (247) (84)
Common stock dividends (39) —
Proceeds from warrants exercised — 2
Issuance of common stock 1 $ —
Net cash used in financing activities $ (285) $ (144)

Lawsuits, Claims, Commitments and Contingencies

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021~~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 94 Lawsuits, Claims, Commitments and Contingencies for further information.

Critical Accounting Estimates and Significant Accounting and Disclosure Changes

There have been no changes to our critical accounting estimates, which are summarized in Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates of our ~~2021~~2022 Annual Report. ~~See~~ ~~Part I, Item 1~~ – ~~Financial Statements, Note 2 Accounting Policy and Disclosure Changes~~ ~~for a discussion of new accounting standards.~~

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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 ~~the potential~~demand considerations for ~~sustained low oil, natural gas~~our products and ~~natural gas liquids prices;~~services;

•~~equipment, service~~ decisions as to production levels and/or ~~labor price inflation~~pricing by OPEC or ~~unavailability;~~U.S. producers in future periods;

•~~legislative or regulatory changes,~~government policy, war and political conditions and events, including ~~those related to (i)~~ the location, drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, (ii) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (iii) the protection of health, safetywar in Ukraine and ~~the environment, (iv) our ability to claim~~oil sanctions on Russia, Iran and ~~utilize tax credits or other incentives, or (v) the transportation, marketing and sale of our products and CO~~2;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 ~~and~~or our carbon management ~~projects;~~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 ~~reserves or resources from development projects or acquisitions,~~ or higher-than-expected production decline rates;

•~~incorrect~~changes to our estimates of reserves and related future cash flows, ~~and the~~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 ~~successfully execute on~~realize the ~~construction~~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 ~~aspects~~parties;

•reorganization or restructuring of ~~the infrastructure projects~~our operations;

•our ability to claim and ~~enter into third party contracts on contemplated terms;~~utilize tax credits or other incentives in connection with our CCS projects;

•our ability to realize the benefits contemplated by ~~the business~~our energy transition strategies and initiatives, ~~related to energy transition,~~ including ~~carbon capture and storage~~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;~~JV, and our ability to convert our CDMAs to definitive agreements and enter into other offtake agreements;

•~~global geopolitical, socio-demographic~~our ability to maximize the value of our carbon management business and ~~economic trends~~operate it on a stand alone basis;

•our ability to successfully develop infrastructure projects and ~~technological innovations;~~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 into our dividend policy and share repurchase program, and our ability to declare future dividends ~~under our debt agreements;~~

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

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

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

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

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

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

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

•our access to and the terms of credit in commercial banking and capital markets, including our ability to ~~achieve expected synergies from joint ventures and acquisitions;~~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;

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

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

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

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

•~~effects of hedging transactions;~~

•~~climate-related conditions and weather events;~~

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

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

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

4442

Item 3Quantitative and Qualitative Disclosures About Market Risk

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2022,~~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 ~~2021~~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 ~~September~~June 30, ~~2022,~~2023, we had a net ~~liabilities~~liability of ~~$191~~$18 million for our commodity derivative ~~commodity~~ positions which are carried at fair value. For more information on our derivative positions as of ~~September~~June 30, ~~2022~~2023, refer to Part I, Item 1 – Financial Statements, Note 105 Derivatives. We have price exposure for natural gas we purchase and use in our business. We used natural gas to generate electricity for our operations and higher natural gas prices will also result in an increase to our electricity costs.

Counterparty Credit Risk

Our credit risk relates primarily to trade receivables and derivative financial instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. Counterparty credit limits have been established based upon the financial health of our counterparties, and these limits are actively monitored. In the event counterparty credit risk is heightened, we may request collateral and accelerate payment dates. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.

As of ~~September~~June 30, ~~2022,~~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 ~~September~~June 30, ~~2022~~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 ~~September~~June 30, ~~2022~~2023. Our Senior Notes bear interest at a fixed rate of 7.125% per annum.

Item 4 Controls and Procedures

Our Chief Executive Officer and ~~our~~ Chief Financial Officer supervised and participated in management's evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of ~~September~~June 30, ~~2022.~~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 ~~September~~June 30, ~~2022~~2023 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

4543

PART II OTHER INFORMATION

Item 1Legal Proceedings

For additional information regarding legal proceedings, see Item 1 – Financial Statements, Note 94 Lawsuits, Claims, Commitments and Contingencies in the Notes to the Condensed Consolidated Financial Statements included in Part I of this Form 10-Q, Part I, Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Lawsuits, Claims, Commitments and Contingencies in this Form 10-Q, and Part I, Item 3, Legal Proceedings in our ~~2021~~2022 Annual Report.

Item 1A Risk Factors

We are subject to various risks and uncertainties in the course of our business. A discussion of such risks and uncertainties may be found under the heading Risk Factors in our ~~2021~~2022 Annual ~~Report.~~Report and our Quarterly Report on Form 10-Q for the three months ended March 31, 2023. Except as set forth below, there were no material changes to those risk factors during the ~~nine~~three months ended ~~September~~June 30, ~~2022.~~2023.

~~New California~~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.

Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products.

To operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local government authorities for a variety of activities including siting, drilling, completion, stimulation, operation, inspection, maintenance, transportation, storage, marketing, site remediation, decommissioning, abandonment, protection of habitat and threatened or endangered species, air emissions, disposal of solid and hazardous waste, fluid injection and disposal and water consumption, recycling and reuse. For example, our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. These operations are subject to regulation by both the City of Long Beach and CalGEM. We are currently in discussions with the City of Long Beach and CalGEM with respect to what injection well pressure gradient complies with CalGEM’s requirements for the protection of underground sources of drinking water while at the same time mitigating subsidence risks. 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. As part of our ongoing discussions, we and the City of Long Beach have provided CalGEM with technical information regarding ~~setbacks~~how the historical injection well pressure gradient complies with CalGEM's requirements and to inform them of the absence of risk of leakage. CalGEM has proposed a meeting for CRC and the City of Long Beach to present their technical findings in more detail, to occur in or around August 2023. As part of that meeting, and subject to its outcome, CalGEM has also proposed that CRC and the City of Long Beach present a work plan for the reduction of injection pressures over a six-month period to levels acceptable to CalGEM. We are ~~expected~~in the process of preparing a response and continue to believe that existing injection pressures address subsidence risks and are protective of underground sources of drinking water. If CalGEM were to ultimately disagree and determine to reduce the ~~value of~~injection well pressure gradient, and we were unable to reverse that decision on appeal or other legal challenge, we expect that any material reduction in injection well pressure gradient for our ~~proved reserves.~~operations in the Wilmington Oil Field would result in a decrease in production and reserves from the field.

~~On September 16, 2022,~~Failure to comply may result in the assessment of administrative, civil and/or criminal fines and penalties, liability for noncompliance, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or prohibiting certain operations or our access to property, water, minerals or other necessary resources, and may otherwise delay or restrict our operations and cause us to incur substantial costs. Under certain environmental laws and regulations, we could be subject to strict or joint and several liability for the removal or remediation of contamination, including on properties over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

Our ability to timely obtain and maintain permits for our operations, including from CalGEM, has from time to time been subject to significant delays and uncertainties and is subject to factor our control. These factors include changes in agency practices, new regulations, or legal challenges to existing approvals for our operations from individual citizens and non-governmental organizations. For example, beginning in 2021, CalGEM ceased issuing new well stimulation permits and has slowed the approval of new drill permits even as it continues approving plugging and workovers. In addition, in 2020 a group of plaintiffs challenged in court the ability of Kern County to issue well permits in reliance on an existing Environmental Impact Report (EIR). See Part I, Item 1 and 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities. We can also provide no assurances that we will always be able to successfully navigate these risks and timely obtain permits or obtain them on favorable terms. While we have existing permits that will allow us to run a modified drilling program in 2023, we are unlikely to be able to offset projected oil production declines over the same period.

Changes to elected or appointed officials or their priorities and policies could result in different approaches to the regulation of the oil and natural gas industry. We cannot predict the actions the Governor of California ~~signed Senate Bill No. 1137 into law, which establishes 3,200 feet as~~or the ~~minimum distance between new~~California legislature may take with respect to the regulation of our business, the oil and natural gas industry or the state’s economic, fiscal or environmental policies, nor can we predict what actions may be taken at the federal level with respect to health, environmental safety, climate, labor or energy laws, regulations and policies, including those that may directly or indirectly impact our operations. 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 ~~wells~~techniques and ~~certain sensitive receptors such as homes, schools~~fluid injection or ~~parks effective January 1, 2023. This bill also imposes health, safety~~disposal, that could increase costs, restrict operations and ~~environmental controls applicable to both current and new wells located within this distance~~change or delay the implementation of sensitive receptors related to noise, light, and dust pollution controls and air emission monitoring, as well as providing for the immediate suspension of operations at production facilities determined to not be in compliance with certain air emission requirements, among other matters. The latter provisions are effective January 1, 2025. We do not expect this bill to result in any changeour business plans" in our existing proved developed producing reserves or current production rates or any material change to the timing of plugging and abandonment liabilities. As a result of this bill, our development plans will change but we do not currently expect its overall pace of development to be affected materially. We will continue to monitor the effects of the new law on our operations.2022 Annual Report.

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 ~~$650 million~~$1.1 billion of our common stock through June 30, ~~2023. On November 2, 2022, our Board of Directors increased the Share Repurchase Program to $850 million and extended the program through December 31, 2023.~~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 ~~September~~June 30, ~~2022~~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)
July 1, 2022 - July 31, 2022 1,122,947 $ 40.00 1,122,947 $ —
August 1, 2022 - August 31, 2022 527,187 $ 45.07 527,187 —
September 1, 2022 - September 30, 2022 271,047 $ 42.73 271,047 —
Total 1,921,181 $ 41.78 1,921,181 $ —


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(a)
April 1, 2023 - April 30, 2023	542,465	$	39.60	542,465	$	—
May 1, 2023 - May 31, 2023	449,631	$	39.70	449,631	—
June 1, 2023 - June 30, 2023	626,650	$	38.28	626,650	—
Total	1,618,746	$	39.12	1,618,746	$	—

(a)The ~~dollar~~total value of shares that may yet be purchased under the Share Repurchase Program totaled ~~$255~~$517 million as of ~~September~~June 30, ~~2022~~2023.

Item 5 Other Disclosures

~~None.~~As previously disclosed, on June 16, 2023, Omar Hayat was appointed to the position Executive Vice President — Operations. In connection with this appointment, the Company and Mr. Hayat entered into an employment agreement, effective July 27, 2023, providing for the following: (i) a base salary of $400,000, (ii) an annual cash bonus with a target value equal to 100% of his annual base salary; (iii) participation in those benefit plans and programs of the Company available to similarly situated executives; (iv) reimbursement for reasonable business-related expenses, subject to the Company’s business expense reimbursement policy; and (v) annual long-term incentive awards (expected to be comprised 60% of performance stock units and 40% of restricted stock units) under the Company’s 2021 Long-Term Incentive Plan (as amended, the “LTIP”) with a target grant value of 400% of Mr. Hayat’s base salary as in effect on the applicable grant date, commencing in calendar year 2024. The performance stock unit awards are expected to vest over a three-year cliff vesting period beginning on the date of grant, and the restricted stock units are expected to vest in three equal installments over a three-year vesting period beginning on the date of grant. The terms and conditions of his LTIP awards will be governed by individual award agreements to be entered into between the Company and Mr. Hayat in connection with the grant of those LTIP awards. He will continue to be a participant in the Company’s Executive Severance Plan.

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			Amended and Restated Credit Agreement, dated as of April 26, 2023, by and among California Resources Corporation, as the Borrower, the several lenders from time to time parties thereto and Citibank, N.A., as Administrative Agent, Collateral Agent and an Issuing Bank (filed as Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q filed on May 4, 2023 and incorporated herein by reference).

10.2**			Employment Agreement by and between Manuela Molina and California Resources Corporation, dated May 8, 2023 (filed as Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on M ay 1 , 2023 and incorporated herein by reference ).

10.3,*			Employment Agreement by and between Omar Hayat and California Resources Corporation, dated July 27, 2023.

10.4,*			Amended and Restated Employment Agreement by and between Christopher D. Gould and California Resources Corporation, dated July 27, 2023.

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

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

32.1*			Certifications of ~~CEO~~Principal Executive Officer and ~~CFO~~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

SIGNATURES

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


			CALIFORNIA RESOURCES CORPORATION


DATE:	~~November 7, 2022~~August 1, 2023	/s/ Noelle M. Repetti
		Noelle M. Repetti
		Senior Vice President and Controller
		(Principal Accounting Officer)


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

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



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

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


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

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

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

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


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

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