UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June 30, 2023~~March 31, 2024

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ___________

Commission file number 001-36478

California Resources Corporation

(Exact name of registrant as specified in its charter)


Delaware						46-5670947
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

1 World Trade Center, Suite 1500

Long Beach, California 90831

(Address of principal executive offices) (Zip Code)

(888) 848-4754

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Exchange Act:


Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock	CRC	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☑ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☑ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act:

Large Accelerated Filer

☑

Accelerated Filer

☐

Non-Accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☑ No

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. ☑ Yes ☐ No

Indicate the number of shares outstanding for each of the issuer's classes of common stock, as of the latest practicable date.

The number of shares of common stock outstanding as of ~~June 30, 2023~~March 31, 2024 was ~~68,962,220.~~68,530,744.

California Resources Corporation and Subsidiaries

Table of Contents


	Page
Part I
Item 1	Financial Statements (unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements of Comprehensive (Loss) Income	6
	Condensed Consolidated Statements of Stockholders' Equity	67
	Condensed Consolidated Statements of Cash Flows	8
	Notes to the Condensed Consolidated Financial Statements	9
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2425
	General	2425
	Pending Aera Merger	25
	Business Environment and Industry Outlook	2426
	Regulatory Updates	25
	~~Supply Chain Constraints and Inflation~~	25
	~~Production~~	26
	~~Prices~~Results of Oil and ~~Realizations~~Gas Operations	2827
	Statements of Operations Analysis	30
	Liquidity and Capital Resources	3733
	Divestitures and Acquisitions	3936
	Lawsuits, Claims, Commitments and Contingencies	3937
	Critical Accounting Estimates and Significant Accounting and Disclosure Changes	4037
	Forward-Looking Statements	4138
Item 3	Quantitative and Qualitative Disclosures About Market Risk	4340
Item 4	Controls and Procedures	4340

Part II
Item 1	Legal Proceedings	4441
Item 1A	Risk Factors	4441
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	4541
Item 5	Other Disclosures	4641
Item 6	Exhibits	4742

GLOSSARY AND SELECTED ABBREVIATIONS

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

•ABR - Alternate base rate.

•ASC - Accounting Standards Codification.

•ARO - Asset retirement obligation.

•Bbl - Barrel.

•Bbl/d - Barrels per day.

•Bcf - Billion cubic feet.

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

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

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

•Btu - British thermal unit.

•CalGEM - California Geologic Energy Management Division.

•CCS - Carbon capture and storage.

•CDMA - Carbon Dioxide Management Agreement.

•CEQA - California Environmental Quality Act.

•CO2 - Carbon dioxide.

•DAC - Direct air capture.

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

•EOR - Enhanced oil recovery.

•EPA - United States Environmental Protection Agency.

•ESG - Environmental, social and governance.

•E&P - Exploration and production.

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

•GAAP - United States Generally Accepted Accounting Principles.

•G&A - General and administrative expenses.

•GHG - Greenhouse gases.

•JV - Joint venture.

•LCFS - Low Carbon Fuel Standard.

•LIBOR - London Interbank Offered Rate.

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

•MBbl/d - One thousand barrels per day.

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

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

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

•MHp - One thousand horsepower.

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

•MMBoe - One million barrels of oil equivalent.

•MMBtu - One million British thermal units.

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

•MMT - Million metric tons.

•MMTPA - Million metric tons per annum.

•MW - Megawatts of power.

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

•NYMEX - The New York Mercantile Exchange.

•OCTG - Oil country tubular goods.

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

•OPEC - Organization of the Petroleum Exporting Countries.

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

•PHMSA - Pipeline and Hazardous Materials Safety Administration.

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

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

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

•PSCs - Production-sharing contracts.

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

•Scope 1 emissions - Our direct emissions.

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

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

•SDWA - Safe Drinking Water Act.

•SEC - United States Securities and Exchange Commission.

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

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

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

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

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

•WTI - West Texas Intermediate.

PART I FINANCIAL INFORMATION

Item 1Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of ~~June 30, 2023~~March 31, 2024 and December 31, ~~2022~~2023

(in millions, except share data)


		June 30,		December 31,
	March 31,							March 31,		December 31,
		2023		2022			2024		2023
CURRENT ASSETS	CURRENT ASSETS					CURRENT ASSETS
Cash and cash equivalents	Cash and cash equivalents	$	448	$	307
Trade receivables	Trade receivables	183		326
Inventories	Inventories	69		60
Assets held for sale	Assets held for sale	13		5
Receivable from affiliate	Receivable from affiliate	29		33
Other current assets, net	Other current assets, net	125		133
Total current assets	Total current assets	867		864
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT	3,303		3,228
Accumulated depreciation, depletion and amortization	Accumulated depreciation, depletion and amortization	(558)		(442)
Total property, plant and equipment, net	Total property, plant and equipment, net	2,745		2,786
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	14		13
DEFERRED TAX ASSET		108		164
DEFERRED INCOME TAXES
OTHER NONCURRENT ASSETS	OTHER NONCURRENT ASSETS	166		140
TOTAL ASSETS	TOTAL ASSETS	$	3,900	$	3,967

CURRENT LIABILITIES

Accounts payable

206

345

Accounts payable

Liabilities associated with assets held for sale

Fair value of commodity derivative contracts

246

Accrued liabilities

299

298

Total current liabilities

582

894

Total current liabilities

NONCURRENT LIABILITIES

Long-term debt, net

593

592

Long-term debt, net

Asset retirement obligations

411

432

Other long-term liabilities

204

185

STOCKHOLDERS' EQUITY

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)

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)

STOCKHOLDERS' EQUITY

Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at March 31, 2024 and December 31, 2023

Common stock (200,000,000 shares authorized at $0.01 par value) (84,460,423 and 83,557,800 shares issued; 68,530,744 and 68,693,885 shares outstanding at March 31, 2024 and December 31, 2023)

Treasury stock (15,929,679 shares held at cost at March 31, 2024 and 14,863,915 shares held at cost at December 31, 2023)

Additional paid-in capital

1,317

1,305

Retained earnings

1,295

938

Accumulated other comprehensive income

Total stockholders' equity

2,110

1,864

Total stockholders' equity

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 six~~ months ended ~~June 30,~~March 31, 2024 and 2023 ~~and 2022~~

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


		Three months ended March 31,
		Three months ended March 31,
		Three months ended March 31,

		Three months ended June 30,				Six months ended June 30,
		2023		2022		2023		2022
REVENUES	REVENUES
REVENUES
REVENUES
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	447	$	718	$	1,162	$	1,346
Net gain (loss) from commodity derivatives		31		(100)		73		(662)
Sales of purchased natural gas		72		75		256		107
Oil, natural gas and NGL sales
Oil, natural gas and NGL sales
Net (loss) gain from commodity derivatives
Net (loss) gain from commodity derivatives
Net (loss) gain from commodity derivatives
Revenue from marketing of purchased commodities
Revenue from marketing of purchased commodities
Revenue from marketing of purchased commodities
Electricity sales	Electricity sales	34		49		102		83
Other revenue		7		5		22		26
Electricity sales
Electricity sales
Interest and other revenue
Interest and other revenue
Interest and other revenue
Total operating revenues
Total operating revenues
Total operating revenues	Total operating revenues	591		747		1,615		900

OPERATING EXPENSES	OPERATING EXPENSES

OPERATING EXPENSES

OPERATING EXPENSES
Operating costs
Operating costs
Operating costs	Operating costs	186		190		440		372
General and administrative expenses	General and administrative expenses	71		56		136		104
General and administrative expenses
General and administrative expenses
Depreciation, depletion and amortization
Depreciation, depletion and amortization
Depreciation, depletion and amortization	Depreciation, depletion and amortization	56		50		114		99
Asset impairment	Asset impairment	—		2		3		2
Asset impairment
Asset impairment
Taxes other than on income
Taxes other than on income
Taxes other than on income	Taxes other than on income	42		42		84		76
Exploration expense	Exploration expense	1		1		2		2
Purchased natural gas expense		27		67		151		88
Exploration expense
Exploration expense
Costs related to marketing of purchased commodities
Costs related to marketing of purchased commodities
Costs related to marketing of purchased commodities
Electricity generation expenses
Electricity generation expenses
Electricity generation expenses	Electricity generation expenses	13		33		62		57
Transportation costs	Transportation costs	16		12		33		24
Transportation costs
Transportation costs
Accretion expense	Accretion expense	11		11		23		22
Accretion expense
Accretion expense
Carbon management business expenses
Carbon management business expenses
Carbon management business expenses
Other operating expenses, net
Other operating expenses, net
Other operating expenses, net	Other operating expenses, net	21		9		34		23
Total operating expenses	Total operating expenses	444		473		1,082		869
Net gain on asset divestitures		—		4		7		58
Total operating expenses
Total operating expenses
Gain on asset divestitures
Gain on asset divestitures
Gain on asset divestitures

OPERATING INCOME		147		278		540		89
OPERATING (LOSS) INCOME

OPERATING (LOSS) INCOME

OPERATING (LOSS) INCOME

NON-OPERATING (EXPENSES) INCOME

NON-OPERATING (EXPENSES) INCOME

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

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

Interest and debt expense

Interest and debt expense

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

Loss from investment in unconsolidated subsidiary

Loss from investment in unconsolidated subsidiary
Other non-operating income (loss)
Other non-operating income (loss)
Other non-operating income (loss)
(LOSS) INCOME BEFORE INCOME TAXES
(LOSS) INCOME BEFORE INCOME TAXES
(LOSS) INCOME BEFORE INCOME TAXES
Income tax benefit (provision)
Income tax benefit (provision)
Income tax benefit (provision)
NET (LOSS) INCOME
NET (LOSS) INCOME
NET (LOSS) INCOME

Net income per share
Net (loss) income per share

Net (loss) income per share

Net (loss) income per share
Basic	Basic	$	1.39	$	2.48	$	5.65	$	0.19
Basic
Basic
Diluted
Diluted
Diluted	Diluted	$	1.35	$	2.41	$	5.47	$	0.19

Weighted-average common shares outstanding	Weighted-average common shares outstanding

Weighted-average common shares outstanding

Weighted-average common shares outstanding
Basic
Basic
Basic	Basic	69.7		76.7		70.5		77.6
Diluted	Diluted	71.9		78.8		72.7		79.6
Diluted
Diluted

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

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

For the three ~~and six~~months ended ~~June 30,~~March 31, 2024 and 2023

(in millions)

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


	Three months ended March 31,
	2024		2023
Net (loss) income	$	(10)	$	301
Other comprehensive income:
Amortization of prior service cost credit included in net periodic benefit cost, net of tax(a)	(2)		—
Comprehensive (loss) income attributable to common stock	$	(12)	$	301

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

(a) Tax effects of the amortization of prior service cost credit were insignificant for the three months ended March 31, 2024.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Stockholders' Equity

For the three ~~and six~~ months ended ~~June 30, 2022~~March 31, 2024 and 2023

(in millions)

Three months ended June 30, 2022
Common Stock Treasury Stock Additional Paid-in Capital Retained Earnings Accumulated Other
Comprehensive
Income Total
Equity
Balance, March 31, 2022 $ 1 $ (219) $ 1,293 $ 286 $ 72 $ 1,433
Net income — — — 190 — 190
Share-based compensation — — 3 — — 3
Repurchases of common stock — (96) — — — (96)
Cash dividend ($0.17 per share) — — — (13) — (13)
Balance, June 30, 2022 $ 1 $ (315) $ 1,296 $ 463 $ 72 $ 1,517


	Three months ended March 31, 2024
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, December 31, 2023	$	1	$	(604)	$	1,329	$	1,419	$	74	$	2,219
Net loss	—		—		—		(10)		—		(10)

Share-based compensation	—		—		7		—		—		7



Repurchases of common stock	—		(58)		—		—		—		(58)

Cash dividend ($0.31 per share)	—		—		—		(22)		—		(22)
Shares cancelled for taxes	—		—		(41)		—		—		(41)
Other comprehensive income, net of tax	—		—		—		—		(2)		(2)
Balance, March 31, 2024	$	1	$	(662)	$	1,295	$	1,387	$	72	$	2,093


	Three months ended March 31, 2023
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, December 31, 2022	$	1	$	(461)	$	1,305	$	938	$	81	$	1,864
Net income	—		—		—		301		—		301

Share-based compensation	—		—		7		—		—		7



Repurchases of common stock	—		(59)		—		—		—		(59)

Cash dividend ($0.2825 per share)	—		—		—		(20)		—		(20)
Shares cancelled for taxes	—		—		(1)		—		—		(1)

Balance, March 31, 2023	$	1	$	(520)	$	1,311	$	1,219	$	81	$	2,092

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 Cash Flows

For the three ~~and six~~ months ended ~~June 30,~~March 31, 2024 and 2023 ~~and 2022~~

(in millions)


		Three months ended March 31,
		Three months ended March 31,
		Three months ended March 31,

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

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

Gain on asset divestitures

Gain on asset divestitures

Other non-cash charges to income, net

Other non-cash charges to income, net

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

CASH FLOW FROM INVESTING ACTIVITIES	CASH FLOW FROM INVESTING ACTIVITIES

CASH FLOW FROM INVESTING ACTIVITIES

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

Other, net

Other, net

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

CASH FLOW FROM FINANCING ACTIVITIES

CASH FLOW FROM FINANCING ACTIVITIES

CASH FLOW FROM FINANCING ACTIVITIES	CASH FLOW FROM FINANCING ACTIVITIES

Repurchases of common stock

Repurchases of common stock

Repurchases of common stock	Repurchases of common stock	(64)		(96)		(123)		(167)
Common stock dividends	Common stock dividends	(20)		(13)		(40)		(26)
Common stock dividends
Common stock dividends
Payments on equity-settled awards
Payments on equity-settled awards
Payments on equity-settled awards

Issuance of common stock	Issuance of common stock	—		—		1		—
Debt amendment costs		(8)		—		(8)		—

Issuance of common stock

Issuance of common stock
Bridge loan commitment and debt amendment costs
Bridge loan commitment and debt amendment costs
Bridge loan commitment and debt amendment costs
Shares cancelled for taxes	Shares cancelled for taxes	(1)		—		(2)		—
Shares cancelled for taxes
Shares cancelled for taxes

Net cash used in financing activities

Net cash used in financing activities

Net cash used in financing activities	Net cash used in financing activities	(93)		(109)		(172)		(193)
(Decrease) increase in cash and cash equivalents	(Decrease) increase in cash and cash equivalents	(29)		(4)		141		19
(Decrease) increase in cash and cash equivalents
(Decrease) increase in cash and cash equivalents
Cash and cash equivalents—beginning of period
Cash and cash equivalents—beginning of period
Cash and cash equivalents—beginning of period	Cash and cash equivalents—beginning of period	477		328		307		305
Cash and cash equivalents—end of period	Cash and cash equivalents—end of period	$	448	$	324	$	448	$	324
Cash and cash equivalents—end of period
Cash and cash equivalents—end of period

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

~~June 30, 2023~~March 31, 2024

NOTE 1 BASIS OF PRESENTATION

We are an independent ~~energy~~oil and natural gas exploration and production and carbon management company operating properties exclusively within California. We are committed to energy ~~transition. We produce~~transition and have some of the lowest carbon intensity ~~oil~~production in the United ~~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.~~States. We are in the early stages of ~~developing~~permitting several carbon capture and storage (CCS) projects ~~and other emissions reducing projects~~ in California. Our ~~subsidiary~~carbon management business, which we refer to as Carbon TerraVault, is expected to build, install, operate and maintain CO2capture equipment, transportation assets and storage facilities in California. In August 2022, ~~Carbon TerraVault~~we entered into a joint venture with BGTF Sierra Aggregator LLC (Brookfield) to pursue ~~certain of these opportunities~~carbon management and storage activities (Carbon TerraVault JV). See Note 23 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV. ~~Separately, we are evaluating the feasibility of a carbon capture system to be located at our Elk Hills power plant.~~

Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.

In the opinion of our management, the accompanying unaudited financial statements contain all adjustments necessary to fairly present our financial position, results of operations, comprehensive income, equity and cash flows for all periods presented. We have eliminated all significant intercompany transactions and accounts. We account for our share of oil and natural gas producing activities, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on our condensed consolidated financial statements. In applying the equity method of accounting, 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, ~~2022 (2022~~2023 (2023 Annual Report).

The carrying amounts of cash, cash equivalents and on-balance sheet financial instruments, other than debt, approximate fair value. Refer to Note 34 Debt for the fair value of our debt.

Certain prior period balances related to natural gas liquid (NGL) marketing activities have been reclassified to conform to our 2024 presentation. For the three months ended March 31, 2023, we reclassified $3 million related to NGL storage activities from other revenue to revenue from marketing of purchased commodities on our condensed consolidated statement of operations.

NOTE 2 PENDING AERA MERGER

On February 7, 2024, we entered into a definitive agreement and plan of merger (Merger Agreement) to combine with Aera Energy, LLC (Aera) in an all-stock transaction (Aera Merger) with an effective date of January 1, 2024. Aera is a leading operator of mature fields in California, primarily in the San Joaquin and Ventura basins, with high oil-weighted production.

Pursuant to the Merger Agreement, we have agreed to issue 21,170,357 shares of common stock (subject to customary adjustments in the event of stock splits, dividend paid in stock and similar items) plus an additional number of shares determined by reference to the dividends declared by us having a record date between the effective date and closing as more fully described in the Merger Agreement. Upon closing, Aera's $950 million outstanding long-term debt will become due as a result of a change in control provision within their legacy debt agreement. We expect to repay a significant portion of this indebtedness with cash on hand and borrowings under our Revolving Credit Facility. We intend to refinance the balance through one or more debt capital markets transactions and, only to the extent necessary, borrowings under a bridge loan facility provided by Citigroup Global Markets, Inc. (the Bank). Under the terms of our debt commitment letter with the Bank, it has committed, subject to satisfaction of customary conditions, to provide us with an unsecured 364-day bridge loan facility in an aggregate principal amount of $500 million (Bridge Loan Facility). Additionally, we have amended our Revolving Credit Facility as described in Note 4 Debt in connection with the pending Aera Merger. During the three months ended March 31, 2024, we incurred $8 million related to the bridge loan commitment and amending our Revolving Credit Facility which is reported in other current assets, net on our condensed consolidated balance sheet.

Closing of the Aera Merger is subject to certain conditions, including, among others, approval of the stock issuance by our stockholders, expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (HSR Act), prior authorization by the Federal Energy Regulatory Commission under Section 203 of the Federal Power Act and other customary closing conditions. The required waiting period under the HSR Act expired on March 25, 2024.

NOTE 23 INVESTMENT IN UNCONSOLIDATED SUBSIDIARY AND RELATED PARTY TRANSACTIONS

In August 2022, our wholly-owned subsidiary Carbon TerraVault I, LLC entered into a joint venture with Brookfield for the further development of a carbon management business in California. We hold a 51% interest in the Carbon TerraVault JV and Brookfield holds a 49% interest. We determined that the Carbon TerraVault JV is a variable interest entity (VIE); however, we share decision-making power with Brookfield on all matters that most significantly impact the economic performance of the joint venture. Therefore, we account for our investment in the Carbon TerraVault JV under the equity method of accounting. Transactions between us and the Carbon TerraVault JV are related party transactions.

Brookfield has committed an initial $500 million to invest in CCS projects that are jointly approved through the Carbon TerraVault JV. As part of the formation of the Carbon TerraVault JV, we contributed rights to inject CO2 into the 26R reservoir in our Elk Hills field for permanent CO2 storage (26R reservoir) and Brookfield committed to make an initial investment of $137 million, payable in three ~~equal~~ installments with the last two installments subject to the achievement of certain milestones. We achieved the milestone for the second installment in March 2024. The third installment will be sized based on permitted storage capacity.

Brookfield contributed the first $46 million installment of their initial investment to the Carbon TerraVault JV in ~~2022. This amount~~2022 and the second $46 million installment was recorded as a receivable from affiliate on our condensed consolidated balance sheet as of March 31, 2024. The remaining balance of the initial installment plus the second installment 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 not met, the first and second installment of the initial investment by Brookfield is reflected as a contingent liability included in other long-term liabilities on our condensed consolidated balance sheets. The contingent liability was $99 million and $52 million at March 31, 2024 and December 31, 2023, respectively.

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

The tables below present the summarized financial information related to our equity method investment ~~and~~in the Carbon TerraVault JV (and do not include amounts we have incurred related to development of our carbon management business, Carbon TerraVault) along with related party transactions for the periods presented.


		June 30,		December 31,
		2023		2022
		(in millions)
		March 31,
		March 31,
		March 31,					December 31,
	2024					2024			2023
	(in millions)							(in millions)
Investment in unconsolidated subsidiary(a)	Investment in unconsolidated subsidiary(a)	$	14	$	13
Receivable from affiliate(b)	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
Other long-term liabilities - Contingent liability (related to Carbon TerraVault JV put and call rights)

(a)Reflects our investment less losses allocated to us of $3 million and $1$9 million for the ~~six~~three months ended ~~June 30, 2023~~March 31, 2024 and the year ended December 31, ~~2022,~~2023, respectively.

(b)The amount of Brookfield's contributions available to us and amounts due to us under the MSA (described further below) are reported as receivable from affiliate. At ~~June 30, 2023,~~March 31, 2024, the amount of ~~$29~~$66 million includes ~~$28~~the remaining $63 million of Brookfield's first and second installments of their initial investment which ~~may be distributed~~is available to us ~~or used to satisfy future capital calls~~ and $1$3 million related to the MSA and vendor reimbursements. At December 31, ~~2022,~~2023, the amount of ~~$33~~$19 million includes ~~$32~~$17 million ~~which may be distributed~~remaining of Brookfield's initial contribution available to us ~~or used to satisfy future capital calls~~ and $1$2 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.~~


	Three months ended March 31,
	2024		2023
	(in millions)
Loss from investment in unconsolidated subsidiary	$	3	$	2
General and administrative expenses(a)	$	2	$	1

~~(d)~~(a)~~These amounts were included in other long-term liabilities~~General and administrative expenses on our condensed consolidated ~~balance sheet. Our obligation due to repurchase features related~~statements of operations have been reduced by this amount which we have invoiced 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~~Carbon TerraVault JV under the MSA for ~~administrative,~~back-office operational and commercial services.

10We are also performing well abandonment work at our Elk Hills field as part of the permitting process for injection of CO2 at the 26R reservoir. During the three months ended March 31, 2024 and 2023, we performed abandonment work and sought reimbursement in the amounts of $4 million and $1 million, respectively, from the Carbon TerraVault JV.

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 34 DEBT

As of ~~June 30, 2023~~March 31, 2024 and December 31, ~~2022,~~2023, our long-term debt consisted of the following:


		March 31,
		March 31,
		March 31,
		2024
		2024
		2024												2023		Interest Rate	Maturity
	(in millions)
		June 30,		December 31,
Revolving Credit Facility
		2023		2022		Interest Rate	Maturity
		(in millions)
Revolving Credit Facility

Revolving Credit Facility	Revolving Credit Facility	$	—	$	—	SOFR plus 2.50%-3.50% ABR plus 1.50%-2.50%(a)	July 31, 2027(b)	$	—		$	$	—		SOFR plus 2.50%-3.50% ABR plus 1.50%-2.50%(a)	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
Senior Notes										545				545		7.125%	February 1, 2026
Principal amount	Principal amount	$	600	$	600
Unamortized debt issuance costs	Unamortized debt issuance costs	(7)		(8)
Unamortized debt issuance costs
Unamortized debt issuance costs
Long-term debt, net	Long-term debt, net	$	593	$	592
Long-term debt, net
Long-term debt, net

(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 April 26, 2023, we entered into an Amended and Restated Credit Agreement (Revolving Credit Facility) with Citibank, N.A., as administrative agent, and certain other lenders, which ~~amends~~amended and ~~restates~~restated in its entirety the prior credit agreement dated October 27, 2020. As of ~~June 30, 2023,~~March 31, 2024, our Revolving Credit Facility consisted of a senior revolving loan facility with an aggregate commitment of ~~$627 million, which includes a net $25 million increase that occurred during the second quarter of 2023.~~$630 million. Our Revolving Credit Facility also included a sub-limit of $250 million for the issuance of letters of credit. As of ~~June 30, 2023, $148~~March 31, 2024, $153 million letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters. As of March 31, 2024, we had $477 million of availability on our Revolving Credit Facility after taking into account the $153 million letters of credit outstanding.

~~The recent amendments~~In connection with the Merger Agreement in February 2024, we entered into a second amendment to our Revolving Credit Facility ~~included,~~to, among other ~~things:~~

•~~extending~~things, permit the ~~maturity date~~incurrence of indebtedness under the Bridge Loan Facility. In March 2024, we entered into the third amendment to ~~July 31, 2027;~~

•~~increasing~~ our ~~ability~~Revolving Credit Facility. The amendment facilitated certain matters with respect to ~~make certain restricted payments (such as dividends and share repurchases)~~the Aera Merger, including the postponement of the regular spring borrowing base redetermination until the fall of 2024 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.~~other amendments.

~~We also amended the interest rates~~In March 2024, we obtained commitments from our existing lenders and ~~fees we pay under~~certain new lenders to amend our Revolving Credit ~~Facility. Interest is payable quarterly for ABR loans and at~~Facility upon the ~~end~~closing of the ~~applicable interest period for term SOFR loans, but not less than quarterly. We also pay a~~Aera Merger. These commitments include increasing our borrowing base from $1.2 billion to $1.5 billion, increasing the aggregate commitment ~~fee on unused capacity ranging~~amount from ~~37.5~~$630 million to ~~50 basis points per annum, depending on~~$1.1 billion and other matters. These commitments are subject to certain conditions prior to becoming effective, including the ~~percentage~~closing of the ~~commitment utilized.~~Aera Merger.

The borrowing base is redetermined semi-annually and was reaffirmed at $1.2 billion on ~~April 26, 2023 as part~~October 30, 2023. The regular spring borrowing base redetermination for 2024 was postponed until the fall of ~~our amendment.~~2024. The borrowing base takes into account the estimated value of our proved reserves, total indebtedness and other relevant factors consistent with customary reserves-based lending criteria. The amount we are able to borrow under our Revolving Credit Facility is limited to the amount of the commitment described above.

~~At June 30, 2023,~~As of March 31, 2024, 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~~2023 Annual Report.

Fair Value

The fair value of our fixed-rate debt at ~~June 30, 2023~~March 31, 2024 and December 31, ~~2022~~2023 was approximately ~~$604~~$549 million and ~~$574~~$554 million, respectively. We estimate fair value based on known prices from market transactions (using Level 1 inputs on the fair value hierarchy).

NOTE 45 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~~March 31, 2024 and December 31, ~~2022~~2023 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~~In March 2024, we entered into a cost sharing agreement with former lessees ~~we will~~to share in ~~on-going~~ongoing maintenance costs during the pendency of the challenge to the BSEE order. We estimate our ongoing share of maintenance costs for the platforms could approximate $5 million to $8 million per year. Due to the preliminary stage of the process, no cost estimates to abandon the offshore platforms have been determined.

NOTE 56 DERIVATIVES

We continue to maintain a commodity hedging program primarily focused on crude oil ~~and to a lesser extent natural gas,~~ to help protect our cash flows, margins and capital program from the volatility of commodity ~~prices~~prices. We also enter into natural gas swaps for the purpose of hedging our fuel consumption at one of our steamfloods as well as swaps for natural gas purchases and sales related 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~~March 31, 2024 and ~~2022.~~2023. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to implement our hedging strategy.

12Summary of Derivative Contracts

~~Summary of open derivative contracts on oil~~ — We held the following Brent-based contracts as of ~~June 30, 2023:~~March 31, 2024:

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.~~


	Q2 2024		Q3 2024		Q4 2024		1H 2025		2H 2025
Sold Calls
Barrels per day	30,000		30,000		29,000		28,000		27,500
Weighted-average price per barrel	$	90.07	$	90.07	$	90.07	$	86.88	$	86.90

Purchased Puts
Barrels per day	30,000		30,000		29,000		28,000		27,500
Weighted-average price per barrel	$	65.17	$	65.17	$	65.17	$	61.43	$	61.45

Swaps
Barrels per day	8,875		8,875		5,500		3,500		3,250
Weighted-average price per barrel	$	79.28	$	80.10	$	77.45	$	72.81	$	72.50

The outcomes of the derivative positions are as follows:

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

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

•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~~

At March 31, 2024, we also held the following swaps to hedge purchased ~~puts – we receive settlement payments for prices below~~natural gas used in our operations as shown in the ~~indicated weighted-average price per barrel.~~table below.


	Q2 2024		Q3 2024		Q4 2024
Swaps:
MMBtu per day	10,000		10,000		10,000
Weighted-average price per MMBtu	$	5.65	$	5.65	$	5.65

~~Fair value~~

We also have a limited number 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~~derivative contracts related to our ~~Brent based~~natural gas marketing activities are intended to lock in locational price spreads. These derivative contracts are not significant to our results of operations or financial statements taken as a whole.

Fair Value of Derivatives

Derivative instruments not designated as hedging instruments are required to be recorded on the balance sheet at fair value. We report gains and losses on our derivative contracts which hedge commodity price risk related to our oil production and our marketing activities in operating revenue on our consolidated statements of operations as shown in the table ~~above, we held swaps as of June 30, 2023~~below:


	Three months ended March 31,
	2024		2023
(in millions)
Non-cash commodity derivative (loss) gain	$	(59)	$	107


Settlements and premiums	(12)		(65)

Net (loss) gain from commodity derivatives	$	(71)	$	42

We report gains and losses on our derivative contracts for purchased natural gas used to ~~secure~~generate steam for our steamflood operations as a ~~margin for future physical sales~~component of ~~natural gas related to~~operating expense on our ~~marketing and trading activities. The fair value~~consolidated statement of ~~these natural gas hedges was~~operations. For the three months ended March 31, 2024, we recognized a net loss of $1 million ~~included in other current assets, net~~(which includes a non-cash gain of $1 million and $2 million ~~included~~of settlement payments) 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~~other operating expenses, net on our ~~Brent based~~consolidated statement of operations. We did not have derivative contracts ~~in the table above, we held swaps as of December 31, 2022 for~~related to purchased 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~~the three months ended March 31, ~~2022.~~2023.

Our derivative contracts are measured at fair value using industry-standard models with various inputs, including quoted forward prices, and are classified as Level 2 in the required fair value hierarchy for the periods presented. We recognized fair value changes on derivative instruments each reporting period in net gain (loss) from commodity derivatives on our condensed consolidated statements of operations for the three and 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 fair values of our outstanding commodity derivatives as of March 31, 2024 and December 31, 2023:


March 31, 2024
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
	(in millions)
Other current assets, net	$	11	$	(11)	$	—
Other noncurrent assets	24		(24)		—

Current liabilities	(46)		11		(35)
Noncurrent liabilities	(38)		24		(14)
	$	(49)	$	—	$	(49)


December 31, 2023
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
	(in millions)
Other current assets, net	$	39	$	(18)	$	21
Other noncurrent assets	38		(32)		6

Current liabilities	(26)		18		(8)
Noncurrent liabilities	(34)		32		(2)
	$	17	$	—	$	17

NOTE 7 INCOME TAXES

The following table presents the components of our total income tax provision:


	Three months ended March 31,
	2024		2023
	(in millions)
(Loss) income before income taxes	$	(19)	$	376

Current income tax provision	—		28
Deferred income tax (benefit) provision	(9)		47
Total income tax (benefit) provision	$	(9)	$	75

Our income tax provision ~~and a~~or benefit for interim periods is determined by applying an estimated annual effective tax rate to (loss) income before income taxes with the result adjusted for discrete items, if any, in the relevant period. A reconciliation of the U.S. federal statutory tax rate to effective tax rate, including discrete items, for the three months ended March 31, 2024 and 2023 is shown below:


	Three months ended March 31,
	2024		2023
U.S federal statutory tax rate	21	%	21	%
State income taxes, net	7		7
Other	3		—
Annual effective tax rate	31	%	28	%
Discrete items:
Stock compensation and other	16		—
Change in the valuation allowance	—		(8)
Effective tax rate	47	%	20	%

Our annual effective tax rate of 31% differed from the U.S. federal statutory tax rate of 21% for the three months ended March 31, 2024 primarily due to state taxes and disallowed executive compensation expense. During the three months ended March 31, 2024, we recognized an income tax benefit related to the settlement of certain equity-settled stock-based compensation awards, which have the effect of increasing 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 %
rate by 16%.

Our annual effective tax rate of 28% differed from the U.S. federal statutory tax rate of 21% for the three months ended March 31, 2023 due to state taxes. During the ~~six~~three months ended ~~June 30, 2022,~~March 31, 2023 we recognized a tax benefit for the release of 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~~recorded in 2022 related to a capital loss generated from the ~~six months ended June 30, 2023, we recognized the benefit~~divestiture of ~~this tax loss by releasing the valuation allowance after we jointly agreed to amend the original tax treatment with the buyer.~~oil and gas assets. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 ~~Divestitures and Acquisitions~~Income Taxes in our 2023 Annual Report for ~~more information on our Lost Hills transaction.~~additional information.

Management expects to realize the recorded deferred tax assets primarily through future income and reversal of taxable temporary differences. Realization of our existing deferred tax assets is ~~subjective~~not assured and ~~remains dependent~~depends on a number of factors including our ability to generate sufficient taxable income in future periods.

NOTE 78 DIVESTITURES AND ACQUISITIONS

Divestitures

Fort Apache in Huntington Beach

In March 2024, we sold our 0.9-acre Fort Apache real estate property in Huntington Beach, California for a purchase price of $10 million and recognized a $6 million gain.

Ventura Basin Transactions

~~In the three~~During 2021 and ~~six months ended June 30,~~ 2022, we ~~recorded a gain of $4 million and $10 million, respectively, related~~entered into transactions to ~~the sale of certain~~sell our Ventura basin assets. The transaction contemplates multiple closings that are subject to customary closing conditions. The closing of the sale of our remaining assets in the Ventura basin is subject to final approval from the State Lands Commission, which we expect ~~to receive~~could occur in ~~the second half of 2023.~~2024. These remaining assets, consisting of property, plant and equipment, and associated asset retirement obligations are classified as held for sale on our condensed consolidated balance sheets at ~~June 30, 2023~~March 31, 2024 and December 31, ~~2022.~~2023. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 38 Divestitures and Acquisitions in our ~~2022~~2023 Annual Report for additional information on the Ventura basin transactions.

~~Lost Hills Transaction~~

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 until January 1, 2026. We also retained 100% of the deep rights and related seismic data.~~

Other

During the ~~six~~three months ended ~~June 30,~~March 31, 2023, we sold a non-producing asset in exchange for the assumption of liabilities, recognizing a $7 million ~~gain. During~~gain related to the ~~six months ended June 30, 2022, we sold non-core assets recognizing an insignificant loss.~~liability reduction.

Acquisitions

~~During the six months ended June 30,~~In 2022, we acquired properties for carbon management activities for approximately $17 million. We ~~are evaluating the sale~~intend to divest a portion of ~~certain unwanted~~these assets ~~that were part of this acquisition~~ and ~~recognized~~recorded these assets at fair value recognizing an impairment of $3 million in the first quarter of 2023. The fair value, ~~of these assets,~~ using Level 3 inputs in the fair value hierarchy, declined during the first quarter of 2023 due to market conditions ~~including~~(including inflation and rising interest ~~rates. These unwanted~~rates). The assets being divested are classified as held for sale as of ~~June 30, 2023~~March 31, 2024 on our condensed consolidated balance sheet.

NOTE 89 STOCKHOLDERS' EQUITY

Share Repurchase Program

Our Board of Directors has authorized a Share Repurchase Program to acquire up to ~~$1.1~~$1.35 billion of our common stock through ~~June 30, 2024.~~December 31, 2025. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend or discontinue authorization of the program at any time. The following is a summary of our share repurchases, which is held as treasury stock, for the periods presented:

Total Number of Shares Purchased Total Value of Shares Purchased Average Price Paid per Share
(number of shares) (in millions) ($ per share)
Three months ended 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


	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 March 31, 2023	1,423,764	$	59	$	41.25
Three months ended March 31, 2024	1,065,764	$	58	$	53.26




Inception of Program (May 2021) through March 31, 2024	15,929,679	$	662	$	41.39

Note: The total value of shares purchased includes approximately $1 million in both the ~~six~~three months ended ~~June 30,~~March 31, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning inon January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented.

Dividends

~~On February 23, 2023, our~~Our Board of Directors declared ~~a quarterly~~the following cash ~~dividend~~dividends for each of ~~$0.2825 per share of common stock 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 was paid on March 16, 2023. On April 28, 2023, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock 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.periods presented.


	Total Dividend		Rate Per Share
	(in millions)		($ per share)

Three months ended March 31, 2024	$	21	$	0.31




Three months ended March 31, 2023	$	20	$	0.2825

In addition to dividends on our common stock shown in the table above, we paid $4 million on equity-settled stock-based compensation awards in the three months ended March 31, 2024. 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 1314 Subsequent ~~Event~~Events for information on future cash dividends.

Warrants

In October 2020, we reserved an aggregate 4,384,182 shares of our common stock for warrants which are exercisable at $36 per share through October 26, 2024.

As of ~~June 30, 2023,~~March 31, 2024, we had outstanding warrants exercisable into ~~4,295,157~~4,163,670 shares of our common stock (subject to adjustments pursuant to the terms of the warrants). During the three ~~and six~~ months ended ~~June 30,~~March 31, 2024, we issued 18,851 shares of our common stock in exchange for warrants. During the three months ended March 31, 2023, ~~and 2022,~~ we issued an insignificant ~~amount~~number of shares of our common stock in exchange for warrants.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 1110 Stockholders' Equity in our ~~2022~~2023 Annual Report for additional information on the terms of our warrants.

NOTE 910 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) were calculated using the treasury stock method for the three ~~and six~~ months ended ~~June 30, 2023~~March 31, 2024 and ~~2022.~~2023. Our restricted stock unit (RSU) and performance stock unit (PSU) awards are not considered participating securities since the dividend rights on unvested shares are forfeitable.

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

The following table presents the calculation of basic and diluted EPS, for the three ~~and six~~ months ended ~~June 30, 2023~~March 31, 2024 and ~~2022:~~2023:


		Three months ended March 31,
		Three months ended March 31,
		Three months ended March 31,
		2024
		2024
		2024
		(in millions, except per-share amounts)
		(in millions, except per-share amounts)
		(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS
Net (loss) income
Net (loss) income
Net (loss) income

		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

Denominator for Basic EPS

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

Potential Common Shares, if dilutive:
Potential common shares, if dilutive:

Potential common shares, if dilutive:

Potential common shares, if dilutive:
Warrants	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
Warrants
Warrants
Restricted stock units
Restricted stock units
Restricted stock units
Performance stock units
Performance stock units
Performance stock units

Denominator for Diluted EPS

Denominator for Diluted EPS

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

EPS

EPS

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

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


	Three months ended March 31,
	2024	2023
(in millions)
Shares issuable upon exercise of warrants	4.2	—
Shares issuable upon settlement of RSUs	0.9	—
Shares issuable upon settlement of PSUs	1.1	—
Total antidilutive shares	6.2	—

NOTE 1011 SUPPLEMENTAL ACCOUNT BALANCES

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

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


		Three months ended March 31,
		Three months ended June 30,				Six months ended June 30,
		Three months ended March 31,
		2023		2022			2023		2022
		(in millions)
		Three months ended March 31,
		2024
		2024
		2024
		(in millions)
		(in millions)
		(in millions)
Oil	Oil	$	362	$	547		$	752	$	1,033
Natural gas	Natural gas	43		94			306		174
Natural gas
Natural gas
NGLs
NGLs
NGLs	NGLs	42		77			104		139
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	447	$	718		$	1,162	$	1,346

Oil, natural gas and NGL sales
Oil, natural gas and NGL sales

1719

From time-to-time, we enter into transactions for third-party production, which we report as revenue from marketing of purchased commodities on our condensed consolidated statement of operations. Revenues from marketing of purchased commodities primarily results from the storage or transportation of natural gas to take advantage of differences in pricing or location or in the quality of other products. The following table provides disaggregated revenue for sales to customers related to our marketing activities:



	Three months ended March 31,
	2024		2023
	(in millions)
Oil	$	20	$	—
Natural gas	48		184
NGLs	6		3
Revenue from marketing of purchased commodities	$	74	$	187

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)
		March 31,
		March 31,
		March 31,					December 31,
	2024					2024			2023
	(in millions)							(in millions)
Materials and supplies	Materials and supplies	$	65	$	56
Finished goods	Finished goods	4		4
Inventories	Inventories	$	69	$	60

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


		June 30,		December 31,
		2023		2022
		(in millions)
		March 31,
		March 31,
		March 31,					December 31,
	2024					2024			2023
	(in millions)							(in millions)
Net amounts due from joint interest partners(a)	Net amounts due from joint interest partners(a)	$	32	$	39

Fair value of commodity derivative contracts	Fair value of commodity derivative contracts	37		39
Fair value of commodity derivative contracts
Fair value of commodity derivative contracts
Prepaid expenses	Prepaid expenses	21		17
Greenhouse gas allowances	Greenhouse gas allowances	16		—
Natural gas margin deposits		3		16

Income tax receivable
Income tax receivable
Income tax receivable	Income tax receivable	4		10
Other	Other	12		12
Other current assets, net	Other current assets, net	$	125	$	133

(a)Included in the ~~June 30, 2023~~March 31, 2024 and December 31, ~~2022~~2023 net amounts due from joint interest partners are allowances of $1$3 million.

Other noncurrent assets — Other noncurrent assets include the following:


		June 30,		December 31,
		2023		2022
		(in millions)
		March 31,
		March 31,
		March 31,					December 31,
	2024					2024			2023
	(in millions)							(in millions)
Operating lease right-of-use assets	Operating lease right-of-use assets	$	83	$	73
Deferred financing costs - Revolving Credit Facility	Deferred financing costs - Revolving Credit Facility	12		6
Emission reduction credits	Emission reduction credits	11		11
Prepaid power plant maintenance	Prepaid power plant maintenance	31		28
Fair value of commodity derivative contracts	Fair value of commodity derivative contracts	17		7
Deposits and other	Deposits and other	12		15
Other noncurrent assets	Other noncurrent assets	$	166	$	140

1820

Accrued liabilities — Accrued liabilities include the following:


		June 30,		December 31,
		2023		2022
		(in millions)
	March 31,					March 31,		December 31,
	2024					2024		2023
	(in millions)						(in millions)
Employee-related costs	Employee-related costs	$	65	$	49
Taxes other than on income	Taxes other than on income	31		32
Asset retirement obligations	Asset retirement obligations	72		59
Interest	Interest	19		19
Operating lease liability	Operating lease liability	16		18

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

Income taxes payable

Other	Other	28		22
Other
Other
Accrued liabilities	Accrued liabilities	$	299	$	298

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


		June 30,		December 31,
		2023		2022
		(in millions)
		March 31,
		March 31,
		March 31,					December 31,
	2024					2024			2023
	(in millions)							(in millions)
Compensation-related liabilities	Compensation-related liabilities	$	40	$	36
Postretirement benefit plan	Postretirement benefit plan	29		33
Operating lease liability	Operating lease liability	64		52

Fair value of commodity derivative contracts
Premiums due on commodity derivative contracts	Premiums due on commodity derivative contracts	13		8
Contingent liability (related to Carbon TerraVault JV put and call rights)	Contingent liability (related to Carbon TerraVault JV put and call rights)	50		48
Other	Other	8		8
Other long-term liabilities	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 by us under the MSA towith the Carbon TerraVault JV. See Note 23 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)
		Three months ended March 31,
		Three months ended March 31,
		Three months ended March 31,
		2024
		2024
		2024
		(in millions)
		(in millions)
		(in millions)
Exploration and production, corporate and other
Exploration and production, corporate and other
Exploration and production, corporate and other	Exploration and production, corporate and other	$	13	$	9	$	22	$	23
Carbon management business	Carbon management business	8		—		12		—
Total other operating expenses, net		$	21	$	9	$	34	$	23
Carbon management business
Carbon management business
Total general and administrative expenses
Total general and administrative expenses
Total general and administrative expenses

NOTE 1112 SUPPLEMENTAL CASH FLOW INFORMATION

We ~~paid $51 million of~~made U.S. federal and state income tax payments of $22 million during the three ~~and six~~ months ended ~~June 30, 2023.~~March 31, 2024. We ~~paid $20 million of~~did not make U.S. federal or state 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.~~March 31, 2023.

Interest paid, net of capitalized amounts, was ~~insignificant~~$20 million and $21 million for the three months ended ~~June 30,~~March 31, 2024 and 2023, respectively. Interest income was $6 million and ~~$22~~$3 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~~March 31, 2024 and ~~$22 million for the six months ended June 30, 2022.~~2023, respectively.

Non-cash investing activities in the three ~~and six~~ months ended ~~June 30,~~March 31, 2023 included $2 million ~~and $4 million, respectively,~~ related to our share of capital calls by the Carbon TerraVault JV. See Note 23 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV.

Non-cash ~~investing~~financing activities in the three ~~and six~~ months ended ~~June 30, 2022~~March 31, 2024 included approximately $87 million related to the issuance of shares for our stock-based compensation awards. Non-cash financing activities in the three months ended March 31, 2024 also included approximately $1 million ~~of additional earn-out consideration~~ related to ~~our Ventura basin asset divestiture.~~dividend equivalents accrued for stock-based compensation awards and approximately $1 million related to an excise tax on share repurchases. Non-cash financing activities in the three months ended March 31, 2023 included an insignificant amount, for dividend equivalents accrued for stock-based compensation awards and approximately $1 million related to an excise tax on share repurchases.

NOTE 1213 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~~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~~March 31, 2024 and December 31, ~~2022~~2023 and the condensed consolidating statements of operations for the three ~~and six~~ months ended ~~June 30,~~March 31, 2023 and ~~2022,~~2024, 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.

2022

Condensed Consolidating Balance Sheets

As of ~~June 30, 2023~~March 31, 2024 and December 31, ~~2022~~2023


		As of June 30, 2023
		Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
		(in millions)
	As of March 31, 2024														As of March 31, 2024
	Parent											Parent	Combined Unrestricted Subsidiaries	Combined Restricted Subsidiaries		Eliminations	Consolidated
	(in millions)														(in millions)
Total current assets	Total current assets	$	467	$	30	$	370	$	—	$	867
Total property, plant and equipment, net	Total property, plant and equipment, net	12		7		2,726		—		2,745
Investments in consolidated subsidiaries	Investments in consolidated subsidiaries	2,736		(9)		1,530		(4,257)		—
Deferred tax asset	Deferred tax asset	108		—		—		—		108
Investment in unconsolidated subsidiary	Investment in unconsolidated subsidiary	—		14		—		—		14
Other assets	Other assets	14		42		110		—		166
TOTAL ASSETS	TOTAL ASSETS	$	3,337	$	84	$	4,736	$	(4,257)	$	3,900

Total current liabilities	Total current liabilities	95		9		478		—		$	582
Total current liabilities
Total current liabilities
Long-term debt	Long-term debt	593		—		—		—		593
Asset retirement obligations	Asset retirement obligations	—		—		411		—		411
Other long-term liabilities	Other long-term liabilities	77		76		51		—		204
Amounts due to (from) affiliates	Amounts due to (from) affiliates	462		21		(483)		—		—
Total equity	Total equity	2,110		(22)		4,279		(4,257)		2,110
TOTAL LIABILITIES AND EQUITY	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)
	As of December 31, 2023														As of December 31, 2023
	Parent											Parent	Combined Unrestricted Subsidiaries	Combined Restricted Subsidiaries		Eliminations	Consolidated
	(in millions)														(in millions)
Total current assets	Total current assets	$	329	$	33	$	502	$	—	$	864
Total property, plant and equipment, net	Total property, plant and equipment, net	13		6		2,767		—		2,786
Investments in consolidated subsidiaries	Investments in consolidated subsidiaries	2,096		—		1,512		(3,608)		—
Deferred tax asset	Deferred tax asset	164		—		—		—		164
Investment in unconsolidated subsidiary	Investment in unconsolidated subsidiary	—		13		—		—		13
Other assets	Other assets	8		33		99		—		140
TOTAL ASSETS	TOTAL ASSETS	$	2,610	$	85	$	4,880	$	(3,608)	$	3,967

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

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

2123

Condensed Consolidating Statement of Operations

For the three ~~and six~~ months ended ~~June 30,~~March 31, 2024 and 2023 ~~and 2022~~


		Three months ended June 30, 2023
		Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated
		(in millions)
	Three months ended March 31, 2024														Three months ended March 31, 2024
	Parent											Parent	Combined Unrestricted Subsidiaries	Combined Restricted Subsidiaries		Eliminations	Consolidated
	(in millions)														(in millions)
Total revenues	Total revenues	$	5	$	—	$	586	$	—	$	591
Total costs and other	Total costs and other	62		11		371		—		444

Gain on asset divestitures
Non-operating (loss) income	Non-operating (loss) income	(11)		(2)		1		—		(12)
(LOSS) INCOME BEFORE INCOME TAXES	(LOSS) INCOME BEFORE INCOME TAXES	(68)		(13)		216		—		135
Income tax provision		(38)		—		—		—		(38)
Income tax benefit
NET (LOSS) INCOME	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)
	Three months ended March 31, 2023														Three months ended March 31, 2023
	Parent											Parent	Combined Unrestricted Subsidiaries	Combined Restricted Subsidiaries		Eliminations	Consolidated
	(in millions)														(in millions)
Total revenues	Total revenues	$	—	$	—	$	900	$	—	$	900
Total costs and other	Total costs and other	81		7		781		—		869
Gain on asset divestitures	Gain on asset divestitures	—		—		58		—		58
Non-operating (loss) income	Non-operating (loss) income	(27)		—		3		—		(24)
(LOSS) INCOME BEFORE INCOME TAXES	(LOSS) INCOME BEFORE INCOME TAXES	(108)		(7)		180		—		65
Income tax provision	Income tax provision	(50)		—		—		—		(50)
NET (LOSS) INCOME	NET (LOSS) INCOME	$	(158)	$	(7)	$	180	$	—	$	15

NOTE 1314 SUBSEQUENT ~~EVENT~~EVENTS

Dividend

On ~~July 28, 2023,~~May 7, 2024, our Board of Directors declared a quarterly cash dividend of ~~$0.2825~~$0.31 per share of common stock. The dividend is payable to shareholders of record at the close of business on ~~September 1, 2023~~May 31, 2024 and is expected to be paid on ~~September 15, 2023.~~June 14, 2024.

2324

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

General

We are an independent ~~energy~~oil and natural gas exploration and production and carbon management company operating properties exclusively within California. We are committed to energy ~~transition. We produce~~transition and have some of the lowest carbon intensity ~~oil~~production in the United ~~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.~~States. We are in the early stages of ~~developing~~permitting several carbon capture and storage (CCS) projects ~~and other emissions reducing projects~~ in California. ~~We intend~~Our carbon management business, which we refer to ~~pursue some or all of these projects through our~~as Carbon TerraVault, ~~JV that~~is expected to build, install, operate and maintain CO2 capture equipment, transportation assets and storage facilities in California. In August 2022, we ~~formed~~entered into a joint venture with ~~with~~ BGTF Sierra Aggregator LLC (Brookfield)~~. While all of these projects are in early stages, we expect that the size~~ to pursue carbon management and ~~scope of our projects providing these and similar services and capital spent on such projects will continue to grow given our strategy of expansion into carbon management.~~storage activities (Carbon TerraVault JV). For more information about the risks involved in our carbon capture projects, see Part I, Item 1A – Risk Factors in our Annual Report on Form 10-K for the year ended December 31, ~~2022 (2022~~2023 (2023 Annual Report) and for more information on the Carbon TerraVault JV, see Part I, Item 1 – Financial Statements, Note 23 Investment in Unconsolidated Subsidiary and Related Party Transactions.

Pending Aera Merger

Upon completion of the transaction, we currently expect our existing stockholders to own approximately 77% of the combined company and the existing Aera owners to own approximately 23% of the combined company, on a fully diluted basis. The Aera Merger is expected to close around mid-year 2024. Post closing of the Aera Merger, and subject to Board approval, we expect to increase our quarterly dividend.

In the three months ended March 31, 2024, we incurred $13 million of transaction and integration costs related to the Aera Merger included in other operating expenses, net on our condensed consolidated statement of operations. We also incurred $8 million in financing fees, which is included in other current assets, net on our condensed consolidated balance sheet as of March 31, 2024.

Business Environment and Industry Outlook

Commodity Prices

Our operating results and those of the oil and natural gas industry as a whole are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term.

Global oil prices declined slightly in the three months ended June 30, 2023 compared to the three months ended March 31, 2023 as global demand for oil remained generally flat. The decrease in natural gas index prices during the three months ended June 30, 2023 compared to the three months ended March 31, 2023 occurred as North American natural gas production and storage inventories remained relatively high in the second quarter. Refer to Prices and Realizations below for ~~additional~~ information on our realized prices.

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


		Three months ended				Six months ended
		June 30, 2023		March 31, 2023		June 30, 2023		June 30, 2022
		Three months ended
		Three months ended
		Three months ended
		March 31, 2024
		March 31, 2024
		March 31, 2024
Brent oil ($/Bbl)
Brent oil ($/Bbl)
Brent oil ($/Bbl)	Brent oil ($/Bbl)	$	78.01	$	82.22	$	80.12	$	104.59
WTI oil ($/Bbl)	WTI oil ($/Bbl)	$	73.78	$	76.13	$	74.95	$	101.35
WTI oil ($/Bbl)
WTI oil ($/Bbl)
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	$	2.10	$	3.42	$	2.76	$	6.06
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price

Regulatory Updates

Well Permits

CalGEM ~~is California's primary regulator~~remains in the process of developing standard operating procedures for reviewing well permit applications that it commenced in the second half of 2023. Significant permitting delays continue pending CalGEM’s completion of this process. An increase in permits approvals for workovers has continued through the first quarter of 2024, and substantially increased in April 2024. As of May 6, 2024, we have received 73 permits for workovers since the beginning of the ~~oil and natural gas production industry on private and state lands, with additional oversight from the State Lands Commission’s administration~~year. As of ~~state surface and mineral interests. From time to time~~May 6, 2024, we have ~~experienced significant delays~~also received 8 permits for deepenings and 1 permit for a sidetrack for wells in our Wilmington field. With only a few exceptions, there continues to be no new drill permits issued in the state.

Kern County EIR Litigation

On March 7, 2024, the California Court of Appeals, Fifth Appellate District (Court of Appeals), issued its ruling on the six challenges to Kern County’s Supplemental Recirculated Environmental Impact Report (SREIR) for Kern County Zoning Ordinance G-8992 (Ordinance). In its disposition, the Court of Appeals ordered the Trial Court to enter a modified judgement and fourth preemptory writ directing Kern County (i) to set aside approval of the Ordinance, SREIR and related findings of facts and statements of overriding considerations; and (ii) not to present a revised Ordinance for approval until Kern County has (a) prepared a revised SREIR that corrects CEQA violations relating to the (1) rejection of agricultural conservation easements as a form of partial mitigation for the conversion of agricultural land, (2) assessment of cancer risks associated with the drilling of multiple wells near sensitive receptors and (3) analysis of water supply impacts; and (b) circulated the revised SREIR for public review and comment, prepared responses to comments, and certified the revised SREIR.

On March 22, 2024, Kern County released a notice of preparation of the Second Supplemental Revised Environmental Impact Report (SSREIR). We expect that Kern County will prepare a draft SSREIR, circulate it for public comments and thereafter certify the SSREIR and approve the Ordinance. After that, the Trial Court would then consider whether to lift the stay. If that occurs, well permitting could resume assuming no further challenges to the SSREIR.

As a result of the ruling of the Court of Appeals in the Kern County EIR litigation and current lack of permits with respect to ~~obtaining~~our Kern County properties, we currently plan to operate one drilling rig within Kern County in 2024. We have sufficient permits ~~from CalGEM for our operations. A variety~~in hand to keep that rig active through the end of factors outside of our control can lead to such delays. Since December 2022, CalGEM has issued a limited number of permits for new production wells in California, and those permits were issued to other operators. We continue to receive permits from CalGEM for workovers, deepenings, sidetracks and plugging and abandonment operations. For more information, see 2025.~~Part I, Item 1 & 2 – Business and Properties, Regulation of the Industries in Which We Operate~~ ~~in our 2022 Annual Report.~~

~~Our operations~~

CCS Project Permitting

In December 2023, Kern County released a draft EIR prepared in ~~the Wilmington Oil Field utilize injection wells~~connection with our application for conditional use permits for our CTV I CCS project. The project was originally scheduled to ~~reinject produced water pursuant to waterflooding plans. These operations are subject to regulation~~be considered by the ~~City of Long Beach~~Kern County Planning Commission on March 28th; however, based on comments received the Planning Commission required further environmental review before it can consider the project 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 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 indicateddraft EIR. The Planning Commission recommended that the ~~injection well pressure gradient should be reduced from~~consideration of applicable changes to the ~~gradient that has been used for several decades. As part of our ongoing discussions, we~~zoning ordinance 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 themcertification of the ~~absence~~EIR be continued to the August 22, 2024 Planning Commission hearing, at which the Planning Commission will decide whether to recommend the adoption of ~~risk~~the changes to the zoning ordinance and certification of ~~leakage from~~ the ~~injection zone. CalGEM has proposed a~~EIR to the Board of Supervisors. The Board of Supervisors meeting ~~for CRC and the City of Long Beach to present their technical findings in more detail,~~is expected to occur in or around ~~August~~September or October.

Low Carbon Fuel Standard

On February 14, 2024, the California Air Resources Board (CARB) announced that it was postponing the previously scheduled March 21, 2024, public hearing regarding the proposed amendments to the LCFS Regulation released on December 19, 2023. ~~As part of that meeting,~~Due to continuous substantial public feedback on the proposed amendments, CARB intends to release revised proposed amendments for public review and ~~subject~~comment, to ~~its outcome, CalGEM has also proposed that CRC and the City of Long Beach present~~be followed by a work plan for the reduction of injection pressures over a six-month period to levels acceptable to CalGEM. We are 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 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 decrease in production and reserves from the field. For additional information, see ~~Part I, Item 1 & 2 – Business and Properties, Regulation~~public hearing. The release of the ~~Industries in Which We Operate, Regulation~~revised proposed amendments is pending. These revisions may impact the eligibility of ~~Exploration and Production Activities~~ ~~and the Risk factor entitled "~~Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementationcertain of our ~~business plans" in our 2022 Annual Report.~~CCS projects for LCFS credits.

~~Supply Chain Constraints~~Results of Oil and ~~Inflation~~Gas Operations

In 2023, we have experienced relatively flat pricing compared to 2022. Labor costs and 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.

We have taken measures to limit the effects of inflation by entering into contracts for materials and services with terms of one to three years. For contracts that we anticipate renegotiating in the second half of 2023, we expect moderate price increases for certain purchased goods and services. We also continue to look at ways to improve productivity and performance from our workforce and our vendors.

Production

The following table sets forth our average net production of oil, NGLs and natural gas per day in each of the California oil and natural gas basins in which we operated for the periods presented.

Three months ended

Six months ended

June 30, 2023

March 31, 2023

June 30, 2023

June 30, 2022

Three months ended

March 31, 2024

Oil (MBbl/d)

San Joaquin Basin

Los Angeles Basin

Total

NGLs (MBbl/d)

San Joaquin Basin

Total

Natural gas (MMcf/d)

San Joaquin Basin

119

127

San Joaquin Basin

Los Angeles Basin

Sacramento Basin

Total

135

136

146

Total Net Production (MBoe/d)

Total daily net production for the three months ended ~~June 30, 2023,~~March 31, 2024 compared to the three months ended ~~March~~December 31, 2023 decreased by 37 MBoe/d ~~largely~~predominately due to scheduled plant downtime during the first quarter of 2024. The decrease in production also reflects natural production decline ~~and changes~~as well as the divestiture of our share of a non-operated field in ~~NGL storage volumes. This decrease was partially offset by increased production from drilling and workover activity.~~December 2023. Our production-sharing contracts (PSCs), which are described below, ~~negatively impacted~~did not have a significant impact on our net oil production ~~by 1 MBoe/d~~ in the three months ended ~~June 30, 2023~~March 31, 2024 compared to the three months ended ~~March~~December 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 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)

Three months ended

March 31, 2024

(MBoe/d)

Total Net Production

Partners' share under PSC-type contracts

Working interest and royalty holders' share

Changes in NGL inventory and other

Total Gross Production

103

106

Total Gross Production

Production-Sharing Contracts (PSCs)

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. Operating costs, excluding effects of PSC-type contracts is a non-GAAP measure which adjusts for excess costs attributable to PSC-type contracts for the periods presented in the tables below:


		Three months ended
		June 30, 2023				March 31, 2023
		(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs		$	186	$	23.71	$	254	$	31.61
		Three months ended
		Three months ended
		Three months ended
		March 31, 2024
		March 31, 2024
		March 31, 2024
		(in millions)
		(in millions)
		(in millions)
Operating costs(a)
Operating costs(a)
Operating costs(a)
Excess costs attributable to PSC-type contracts
Excess costs attributable to PSC-type contracts
Excess costs attributable to PSC-type contracts	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	$	169	$	21.56	$	236	$	29.38
Operating costs, excluding effects of PSC-type contracts
Operating costs, excluding effects of PSC-type contracts

(a)

Six months ended
June 30, 2023 June 30, 2022
(in millions) ($ per Boe) (in millions) ($ per Boe)
Operating costs $ 440 $ 27.71 $ 372 $ 22.90
Excess costs attributable to PSC-type contracts (35) $ (2.19) (40) $ (2.45)
Operating costs, excluding effects of PSC-type contracts $ 405 $ 25.52 $ 332 $ 20.45
Operating costs related to our exploration and production activities and are presented before elimination entries.

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~~2023 Annual Report.

2728

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~~oil and natural gas operations for the periods presented:

Three months ended
June 30, 2023 March 31, 2023
Price Realization Price Realization
Oil ($ per Bbl)
Brent $ 78.01 $ 82.22
Realized price without derivative settlements $ 75.77 97% $ 78.68 96%
Derivative settlements (12.11) (15.64)
Realized price with derivative settlements $ 63.66 82% $ 63.04 77%
WTI $ 73.78 $ 76.13
Realized price without derivative settlements $ 75.77 103% $ 78.68 103%
Realized price with derivative settlements $ 63.66 86% $ 63.04 83%
NGLs ($ per Bbl)
Realized price (% of Brent) $ 42.48 54% $ 58.88 72%
Realized price (% of WTI) $ 42.48 58% $ 58.88 77%
Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price $ 2.10 $ 3.42
Realized price without derivative settlements ($/Mcf) $ 3.46 165% $ 21.56 630%
Derivative settlements — —
Realized price with derivative settlements ($/Mcf) $ 3.46 165% $ 21.56 630%


		Six months ended
		June 30, 2023			June 30, 2022
		Price		Realization	Price		Realization
		Three months ended
		Three months ended
		Three months ended
	March 31, 2024
		Price
		Price
		Price
Oil ($ per Bbl)	Oil ($ per Bbl)
Oil ($ per Bbl)
Oil ($ per Bbl)
Brent
Brent
Brent	Brent	$	80.12		$	104.59

Realized price without derivative settlements	Realized price without derivative settlements	$	77.25	96%	$	104.07	100%

Realized price without derivative settlements

Realized price without derivative settlements
Derivative settlements	Derivative settlements	(13.90)			(42.36)
Derivative settlements
Derivative settlements
Realized price with derivative settlements
Realized price with derivative settlements
Realized price with derivative settlements	Realized price with derivative settlements	$	63.35	79%	$	61.71	59%

WTI	WTI	$	74.95		$	101.35

WTI

WTI

Realized price without derivative settlements	Realized price without derivative settlements	$	77.25	103%	$	104.07	103%

Realized price without derivative settlements

Realized price without derivative settlements
Realized price with derivative settlements
Realized price with derivative settlements
Realized price with derivative settlements	Realized price with derivative settlements	$	63.35	85%	$	61.71	61%

NGLs ($ per Bbl)	NGLs ($ per Bbl)

NGLs ($ per Bbl)

NGLs ($ per Bbl)
Realized price (% of Brent)	Realized price (% of Brent)	$	50.88	64%	$	72.57	69%
Realized price (% of Brent)
Realized price (% of Brent)
Realized price (% of WTI)
Realized price (% of WTI)
Realized price (% of WTI)	Realized price (% of WTI)	$	50.88	68%	$	72.57	72%

Natural gas	Natural gas

Natural gas

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

Realized price without derivative settlements ($/Mcf)		$	12.44	451%	$	6.58	109%
Derivative settlements		—			(0.07)
Realized price with derivative settlements ($/Mcf)		$	12.44	451%	$	6.51	107%
Realized price ($/Mcf)

Realized price ($/Mcf)

Realized price ($/Mcf)

Oil — Brent prices ~~decreased slightly~~were relatively flat for the three months ended ~~June 30, 2023~~March 31, 2024 compared to the three months ended ~~March~~December 31, ~~2023 as global demand for crude remained generally flat. Oil~~2023. The slight decline in Brent prices inis attributable to general market factors, including developing concern over the six months ended June 30, 2023 were lower than the same prior year period in 2022 as global energy inventories (including crude, refined products and natural gas) stabilized and as Russian crude and refined products continue to reach markets.strength of China’s economy.

NGLs — NGL prices for the three months ended ~~June 30, 2023 decreased~~March 31, 2024 increased compared to the three months ended ~~March~~December 31, 2023 ~~reflecting traditional seasonality in NGL pricing, as well as higher than normal levels~~due to slightly stronger butane demand and development of ~~inventory~~alternative markets for this time of year. NGL prices for the six months ended June 30, 2023 decreased compared to the same prior year period as prices for competing and complementary products (natural gas, crude oil) have declined. For both periods,our natural gasoline. California remained a premium market compared to other North American locations.

Natural Gas — ~~Our realized price for natural~~Natural gas prices decreased for the three months ended ~~June 30, 2023~~March 31, 2024 compared to the three months ended ~~March~~December 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 reflecting the unprecedented pricing experienced in Californiadriven by growing natural gas ~~markets during the first quarter~~production nationally and a surplus of ~~2023.~~natural gas in storage both nationally as well as in California.

Statements of Operations Analysis

~~Results of Oil and Gas Operations~~

The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses and intercompany eliminations, for the three months ended March 31, 2024 and December 31, 2023. All metrics are shown on a per Boe basis ~~for the three months ended June 30, 2023 and March 31, 2023 and the six months ended June 30, 2023 and 2022.~~except as otherwise stated. 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
		Three months ended
		Three months ended
		March 31, 2024
		March 31, 2024
		March 31, 2024
		Three months ended				Six months ended
Total net production (MBoe/d)
		June 30, 2023		March 31, 2023			June 30, 2023		June 30, 2022
Total net production (MBoe/d)
		($ per Boe)
Total net production (MBoe/d)
Total oil, natural gas and NGL sales (in millions)
Total oil, natural gas and NGL sales (in millions)
Total oil, natural gas and NGL sales (in millions)
Energy operating costs
Energy operating costs
Energy operating costs	Energy operating costs	$	7.39	$	15.56		$	11.52	$	9.24
Gas processing costs	Gas processing costs	$	0.64	$	0.62		$	0.63	$	0.55
Gas processing costs
Gas processing costs
Non-energy operating costs	Non-energy operating costs	$	15.68	$	15.43		$	15.56	$	13.11
Non-energy operating costs
Non-energy operating costs
Operating costs
Operating costs
Operating costs	Operating costs	$	23.71	$	31.61		$	27.71	$	22.90

Field general and administrative expenses(a)	Field general and administrative expenses(a)	$	1.40	$	1.49		$	1.45	$	0.92

Field general and administrative expenses(a)

Field general and administrative expenses(a)
Field depreciation, depletion and amortization(b)
Field depreciation, depletion and amortization(b)
Field depreciation, depletion and amortization(b)	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	$	3.70	$	3.73		$	3.72	$	3.20
Field taxes other than on income
Field taxes other than on income

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

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

~~Operating~~Energy operating costs ~~decreased~~were lower on a per Boe basis during the three months ended ~~June 30, 2023~~March 31, 2024 compared to the three months ended ~~March~~December 31, 2023 ~~primarily due to~~where the benefit of lower ~~energy operating costs as~~electricity and natural gas prices ~~in California markets declined~~was predominately offset by lower production volumes between ~~quarters. Operating~~periods. Non-energy 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 as natural gas prices in California experienced unprecedented highs during the first quarter of 2023. Lower production volumes also contributed to the increase on a per Boe ~~basis.~~

~~Field depreciation, depletion and amortization decreased slightly during~~basis between the three months ended ~~June 30, 2023~~March 31, 2024 compared to the three months ended ~~March~~December 31, 2023 due to lower production volumes. Field depreciation, depletion and amortization increased during the six months ended June 30, 2023 compared to the same prior year period 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 lower production volumes ~~in the six months ended June 30, 2023 compared to the six months ended June 30, 2022. Lower production volumes also contributed to the increase on a per Boe basis.~~between periods.

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 1213 Condensed Consolidated Financial Information.

Certain prior period balances related to NGL marketing activities have been reclassified to conform to our 2024 presentation. For the three months ended December 31, 2023, we reclassified $4 million related to NGL storage activities from other revenue to revenue from marketing of purchased commodities on our condensed consolidated statement of operations. We also reclassified $3 million of NGL processing fees from other operating expenses, net to costs related to marketing of purchased commodities.

Three months ended ~~June 30, 2023~~March 31, 2024 compared to ~~March~~December 31, 2023

The following table presents our consolidated operating revenues for the three months ended ~~June 30, 2023~~March 31, 2024 and ~~March~~December 31, 2023:

Three months ended

June 30, 2023

March 31, 2023

(in millions)

Three months ended

March 31, 2024

(in millions)

Oil, natural gas and NGL sales

447

715

Net gain from commodity derivatives

Sales of purchased natural gas

184

Oil, natural gas and NGL sales

Net (loss) gain from commodity derivatives

Revenue from marketing of purchased commodities

Electricity sales

Other revenue

Total operating revenues

591

1,024

Total operating revenues

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were ~~$447~~$429 million for the three months ended ~~June 30, 2023,~~March 31, 2024, which is a decrease of ~~$268~~$54 million compared to ~~$715~~$483 million for the three months ended ~~March~~December 31, 2023. This decrease was primarily due to lower production volumes and lower realized prices for the ~~second~~first quarter of ~~2023~~2024 as shown in the table below. The effect of cash settlements on our commodity derivative contracts is not included in the table below.

Oil NGLs Natural Gas Total
(in millions)
Three months ended March 31, 2023 $ 390 $ 62 $ 263 $ 715
Changes in realized prices (15) (18) (221) (254)
Changes in production (13) (2) 1 (14)
Three months ended June 30, 2023 $ 362 $ 42 $ 43 $ 447


	Oil		NGLs		Natural Gas		Total
	(in millions)
Three months ended December 31, 2023	$	380	$	47	$	56	$	483
Change in realized prices	(9)		1		(9)		(17)
Change in production	(23)		1		(9)		(31)
Change in intercompany sales of natural gas	—		—		(6)		(6)
Three months ended March 31, 2024	$	348	$	49	$	32	$	429

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

~~The effect of cash settlements on our~~Net (loss) gain from commodity ~~derivative contracts is not included in the table above. Payments on~~derivatives— Net loss from commodity derivatives ~~were $63 million for the three months ended June 30, 2023 compared to $65~~was $71 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 decreased by $266 million~~2024 compared to ~~the three months ended March 31, 2023.~~

~~Net~~net gain ~~from commodity derivatives~~ ~~— Net gain from commodity derivatives was $31~~of $119 million for the three months ended ~~June 30, 2023 compared to $42 million for the three months ended March~~December 31, 2023. The ~~change~~net loss from commodity derivatives 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:~~curves at the end of each measurement period.

Three months ended
June 30, 2023 March 31, 2023
(in millions)
Non-cash commodity derivative gain $ 94 $ 107
Net cash payments on settled commodity derivatives (63) (65)
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~~Payments on commodity derivatives were $72 million for the three months ended June 30, 2023, a decrease of $112 million from $184 million during the three months ended March 31, 2023. The decrease was primarily the result of lower market prices for natural gas. Our natural gas sales net of related purchased natural gas expense were $45 million for the three months ended June 30, 2023 compared to $60$12 million for the three months ended March 31, 2024 compared to $49 million for the three months ended December 31, 2023. Including the effect of settlement payments for commodity derivatives, the realized prices received for our oil, natural gas and NGL sales decreased by $17 million compared to the three months ended December 31, 2023.


	Three months ended
	March 31, 2024		December 31, 2023
	(in millions)
Non-cash commodity derivative (loss) gain	$	(59)	$	168


Settlements and premiums	(12)		(49)

Net (loss) gain from commodity derivatives	$	(71)	$	119

Electricity sales— Electricity sales decreased by $27 million to $15 million for the three months ended March 31, 2024 compared to $42 million for the three months ended December 31, 2023 due to downtime at our Elk Hills power plant for planned maintenance and lower electricity prices in the first quarter of 2024.

~~Electricity sales~~ — Electricity sales decreased by $34 million to $34 million for the three months ended June 30, 2023 compared to $68 million for the three months ended March 31, 2023 predominately due to higher power prices during the first quarter of 2023.

The following table presents our consolidated operating and non-operating expenses and income for the three months ended ~~June 30, 2023~~March 31, 2024 and ~~March~~December 31, 2023:

Three months ended

June 30, 2023

March 31, 2023

(in millions)

Three months ended

March 31, 2024

(in millions)

Operating expenses

Energy operating costs

125

Energy operating costs

Gas processing costs

Non-energy operating costs

123

124

Non-energy operating costs

General and administrative expenses

Depreciation, depletion and amortization

Asset impairment

—

Depreciation, depletion and amortization

Taxes other than on income

Exploration expense

Purchased natural gas expense

124

Exploration expense

Costs related to marketing of purchased commodities

Electricity generation expenses

Transportation costs

Accretion expense

Carbon management business expenses

Other operating expenses, net

Total operating expenses

444

638

Total operating expenses

Gain on asset divestitures

—

Operating income

147

393

Gain on asset divestitures

Operating (loss) income

Non-operating (expenses) income

Interest and debt expense

(14)

Interest and debt expense

Loss on early extinguishment of debt

Loss from investment in unconsolidated subsidiary

(1)

(2)

Other non-operating (expense) income

(1)

Income before income taxes

135

376

Income tax provision

(38)

(75)

Net income

301

Loss from investment in unconsolidated subsidiary

Other non-operating income

(Loss) income before income taxes

Income tax benefit (provision)

Net (loss) income

Energy operating costs — Energy operating costs for the three months ended ~~June 30, 2023~~March 31, 2024 were ~~$58~~$53 million, which was a decrease of ~~$67~~$12 million from ~~$125~~$65 million for the three months ended ~~March~~December 31, 2023. This decrease was aprimarily the result of lower electricity and natural gas prices in the ~~second~~first quarter of ~~2023.~~2024. For more information on ~~our~~ natural gas market prices, see Prices and 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 June 30, 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 ~~$71 million for the three months ended June 30, 2023, which was an increase of $6 million from $65~~$57 million for the three months ended March 31, 2024, which was a decrease of $9 million from $66 million for the three months ended December 31, 2023. The ~~increase~~decrease in G&A expenses was primarily attributable to a reduction in 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.~~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 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~~Stock-based compensation awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest at the end of a two- or three-year period or vest ratably over a two- or three-year period. Our equity-settled awards granted to non-employee directors are restricted stock units that vest ratably over a three-year period. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period.

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

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

Three months ended
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 $27 million of natural gas for marketing activities during the three months ended June 30, 2023, which was a decrease of $97 million from $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, 2023 were $13 million, which was a decrease of $36 million from $49 million for the three months ended March 31, 2023. This decrease was primarily due to lower prices for natural gas.

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

3332

~~Six months ended June 30, 2023 compared to June 30, 2022~~

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

Six months ended
June 30, 2023 June 30, 2022
(in millions)
Oil, natural gas and NGL sales $ 1,162 $ 1,346
Net gain (loss) from commodity derivatives 73 (662)
Sales of purchased natural gas 256 107
Electricity sales 102 83
Other revenue 22 26
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 $1,162 million for the six months ended June 30, 2023, which is a decrease of $184 million compared to $1,346 million for the six months ended June 30, 2022. This decrease was primarily due to changes in realized prices as shown in the table below, including lower realized prices for oil and NGLs partially offset by higher realized prices for natural gas.

Oil NGLs Natural Gas Total
(in millions)
Six months ended June 30, 2022 $ 1,033 $ 139 $ 174 $ 1,346
Changes in realized prices (266) (42) 155 (153)
Changes in production (15) 7 (23) (31)
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 $128 million for the six months ended June 30, 2023 compared to payments of $422 million for the six months ended June 30, 2022. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $110 million compared to the six months ended June 30, 2022.

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

Six months ended
June 30, 2023 June 30, 2022
(in millions)
Non-cash commodity derivative gain (loss) $ 201 $ (240)
Net cash payments on settled commodity derivatives (128) (422)
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 $256 million for the six months ended June 30, 2023, an increase of $149 million from $107 million during the six months ended June 30, 2022. The increase was primarily the result of higher marketing activity and higher market prices in 2023. Our natural gas sales net of related purchased natural gas expense were $105 million for the six months ended June 30, 2023 compared to $19 million for the six months ended June 30, 2022.

~~Electricity sales~~ — Electricity sales increased by $19 million to $102 million for the six months ended June 30, 2023 compared to $83 million for the six months ended June 30, 2022. The increase was predominately a result of higher power prices in the first quarter of 2023 compared to the prior year. Our electricity 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 six months ended June 30, 2023 and 2022:~~

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 six months ended June 30, 2023 were $183 million, which was an increase of $33 million from $150 million for the six months ended June 30, 2022. This increase was a result of higher prices in the first six months of 2023 compared to the same prior year period. For more information on our natural gas market prices, see ~~Prices and Realizations~~ ~~above.~~

~~Non-energy operating costs~~ — Non-energy operating costs were $247 million for the six months ended June 30, 2023, which was an increase of $34 million from $213 million for the six months ended June 30, 2022. The increase was predominately a result of higher downhole maintenance 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 six months ended June 30, 2023 and 2022, respectively. See ~~General and administrative expenses~~ ~~below for additional information on our stock-based compensation awards.~~

~~General and administrative expenses~~ — General and administrative (G&A) expenses were $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 was primarily attributable to compensation-related expenses, including stock-based compensation awards granted in 2023, and 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 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.

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.

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

Six months ended

June 30, 2023

June 30, 2022

(in millions)

Three months ended

March 31, 2024

December 31, 2023

(in millions)

Cash-settled awards

Stock-settled awards

Total included in general and administrative expenses

~~Depreciation, depletion and amortization~~Costs related to marketing of purchased commodities — ~~Depreciation, depletion and amortization (DD&A) increased $15 million~~Costs related to ~~$114~~marketing of purchased commodities were $54 million for the ~~six~~three months ended ~~June 30, 2023 from $99~~March 31, 2024 compared to $42 million for the ~~six~~three months ended ~~June 30, 2022.~~December 31, 2023. The increase of $12 million was primarily due to ~~a change in our DD&A rates which are periodically adjusted to reflect current reserve estimates.~~higher purchases of third-party crude oil.

~~Purchased natural gas expense~~Electricity generation expenses — ~~Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. We purchased $151 million of natural gas~~Electricity generation expenses for ~~marketing activities during~~ the ~~six~~three months ended ~~June 30, 2023,~~March 31, 2024 were $8 million, which was ~~an increase~~a decrease of ~~$63~~$10 million from ~~$88~~$18 million for the ~~six~~three months ended ~~June 30, 2022.~~December 31, 2023. This decrease was primarily due to lower variable operating costs due to downtime resulting from scheduled maintenance of our Elk Hills power plant in the first quarter of 2024.

Other operating expenses, net — Other operating expenses, net increased $16 million to $37 million for the three months ended March 31, 2024 compared to $21 million for the three months ended December 31, 2023. The increase was ~~predominantly~~predominately due to additional expenses related to electricity purchased during the ~~result of higher marketing activity levels~~scheduled maintenance at our Elk Hills power plant as well as transaction and ~~higher market prices in the six months ended June 30, 2023 compared~~integration costs related to the ~~six months ended June 30, 2022. For more information on our natural gas market prices, see~~ ~~Prices and Realizations~~ ~~above.~~Aera Merger.

Income taxes–— The income tax ~~provision~~benefit for the ~~six~~three months ended ~~June 30, 2023~~March 31, 2024 was ~~$113~~$9 million ~~(effective~~(representing an effective tax rate of ~~22%~~47%), compared to ~~$50~~a provision of $79 million ~~(effective~~(representing an effective tax rate of ~~77%~~30%) for the ~~six~~three months ended ~~June 30, 2022. The income~~December 31, 2023. We recognized an excess tax ~~provision for~~benefit as a discrete adjustment in the ~~six months ended June 30, 2022 included a valuation allowance~~first quarter of 2024 related to ~~our Lost Hills divestiture that was released in~~ the ~~six months ended June 30, 2023.~~settlement of certain equity-settled stock-based compensation awards. See Part I, Item 1 – Financial Statements, Note 67 Income Taxes for ~~more~~additional information on ~~a valuation allowance related to~~ our ~~Lost Hills divestiture.~~effective tax rate.

Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity and capital resources are cash flows from operations, cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. 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 ~~six~~three months ended ~~June 30, 2023~~March 31, 2024 were for capital investments, repurchases of our common stock and dividends.

The following table summarizes our liquidity:



	~~June 30, 2023~~March 31, 2024
	(in millions)
Cash and cash equivalents	$	~~448~~403
Revolving Credit Facility:
Borrowing capacity	630		~~627~~
Outstanding letters of credit	~~(148)~~(153)
Availability	$	~~479~~477

Liquidity	$	~~927~~880

~~In April 2023 we~~

We amended our Revolving Credit Facility during the first quarter of 2024 as described in Part I, Item 1 – Financial Statements, Note 4 Debt and continue to evaluate refinancing options for our Senior Notes. In March 2024, we obtained commitments from our existing lenders and certain new lenders to amend our Revolving Credit Facility upon closing of the Aera Merger. These commitments include increasing our borrowing base ~~was reaffirmed at~~from $1.2 ~~billion.~~billion to $1.5 billion, increasing the aggregate commitment amount from $630 million to $1.1 billion and other matters. These commitments are subject to certain conditions prior to becoming effective, including the closing of the Aera Merger.

We intend to undertake certain financing transactions in connection with the Aera Merger. See Part I, Item 1 – Financial Statements, Note ~~3 Debt~~ 2 Pending Aera Merger. We also intend to pursue financing options for ~~more information on~~our carbon management business that are separate from the ~~amendment to~~rest of our ~~Revolving Credit Facility.~~business.

At current commodity prices and based upon our planned ~~2023~~2024 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 (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~~three months ended ~~June 30, 2023,~~March 31, 2024, our operating cash flow ~~increased $77~~decreased $223 million to ~~$418~~$87 million from ~~$341~~$310 million in the same period in ~~2022. The increases~~2023. This decrease in operating cash flow ~~for the six months ended June 30, 2023~~was primarily ~~relates to higher average realized~~driven by lower natural gas prices ~~(increasing sales revenue from~~in California markets during the first quarter of 2024 compared to 2023. Our average natural gas ~~we produce~~prices decreased $17.66 per Mcf from $21.56 per MMcf in the three months ended March 31, 2024 to $3.90 per Mcf during the three months ended March 31, 2024. Further, our natural gas production decreased by 31 MMcf/d from 136 MMcf/d in the three months ended March 31, 2023 to 105 MMcf/d in the three months ended March 31, 2024, also contributing to the decrease.

While our realized oil price with derivative settlements increased by $14.13 per barrel to $77.17 in the three months ended March 31, 2024 from $63.04 in the same prior year period, our net oil production volumes decreased 7 MBbl/d from 55 MBbl/d in the three months ended March 31, 2023 to 48 MBbl/d in the three months ended March 31, 2024. Our total net production volumes decreased by 13 MBoe/d from 89 MBoe/d in the three months ended March 31, 2023 to 76 MBoe/d for the three months ended March 31, 2024 primarily due to scheduled plant downtime during the first quarter of 2024, natural production decline and ~~margins on~~the divestiture of our ~~marketing and trading activities)~~share of a non-operated field in ~~2023~~December 2023. Our PSCs also negatively impacted our net oil production by 1 MBoe/d in the three months ended March 31, 2024 compared to the same ~~prior-year~~prior year period. This increase was partially offset by lower production volumes in 2023 as compared to the same period in 2022. The increase in our revenue was partially offset by an increase in operating costs primarily related to higher prices for purchased natural gas and electricity used in our operations.

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


		Three months ended March 31,

		Three months ended March 31,

		Three months ended March 31,
			2024					2024		2023
			(in millions)						(in millions)
Capital investments
Changes in accrued capital investments
Proceeds from divestitures, net

		Six months ended June 30,
Other, net
				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

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

In March 2024, we sold our 0.9-acre Fort Apache real estate property in Huntington Beach, California. For more information on our divestiture in the three months ended March 31, 2024, see Part I, Item 1 – Financial Statements, Note 8 Divestitures and Acquisitions.

3734

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


		Three months ended March 31,
		Three months ended March 31,
		Three months ended March 31,
			2024					2024		2023
			(in millions)						(in millions)

		Six months ended June 30,
				2023		2022
				(in millions)
Repurchases of common stock(a)

Repurchases of common stock(a)

Repurchases of common stock				$	(123)	$	(167)

Repurchases of common stock(a)
Common stock dividends	Common stock dividends			(40)		(26)
Payments on equity-settled awards

Issuance of common stock	Issuance of common stock			1		$	—
Debt amendment costs				(8)		$	—
Issuance of common stock
Issuance of common stock
Bridge loan commitment and debt amendment costs

Shares cancelled for taxes
Shares cancelled for taxes
Shares cancelled for taxes	Shares cancelled for taxes			(2)		$	—
Net cash used in financing activities	Net cash used in financing activities			$	(172)	$	(193)

(a)The total value of shares purchased includes approximately $1 million in both the three months ended March 31, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented.

~~2023~~A significant number of stock-based compensation awards were settled in the first quarter of 2024. These awards were primarily granted in January 2021 following our emergence from bankruptcy. We withheld shares of common stock to satisfy the tax withholding obligations (shares cancelled for taxes). In addition to the $21 million of dividends paid in the first quarter of 2024, we paid $4 million of dividend equivalents accrued on these stock-based compensation awards.

2024 Capital Program

Our capital program is dynamic in response to commodity price volatility while focusing on oil production and maximizing our free cash flow. WeFollowing the Court of Appeals decision in the Kern County EIR matter, we expect our ~~2023~~2024 capital program to range between $200 million and ~~$245~~$240 million under current ~~conditions with heavier weighting in the second half of the year due~~permitting conditions. Of this amount, $165 million to ~~timing of projects and higher expected workover activity and facilities projects. We expect our capital program~~$185 million is related to oil and natural gas development (including $20 million to ~~continue~~$25 million for maintenance at one of our gas processing facilities at our Elk Hills field), $20 million to ~~be focused primarily on~~$25 million is for carbon management projects and $15 million to $30 million is for corporate and other (including $10 million to $15 million related to scheduled maintenance at our Elk Hills power plant). We expect to run a one rig program for 2024 executing projects using existing ~~permits outside of Kern County.~~permits. Refer to Regulatory Updates above for more information.

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

Three months ended March 31, 2024

~~2023 Full Year Estimate~~

~~Six months ended June 30, 2023~~

(in millions)

Oil and natural gas operations(a)

~~$165 - $195~~

7536

Carbon management business

~~5 - 15~~4

Corporate and other(b)

~~30 - 35~~14

Total Capital

~~$200 - $245~~

8654

(a)During the three months ended March 31, 2024, we incurred an insignificant amount of costs related to planned maintenance at one of our gas processing facilities at our Elk Hills field.

~~We recently amended and extended~~(b)During the three months ended March 31, 2024, we incurred approximately $13 million related to planned maintenance at 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.~~Elk Hills power plant.

Derivatives

Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow, and the inverse applies during periods of rising commodity prices. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. We will continue to evaluate our hedging strategy based on prevailing market prices and conditions.

Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended ~~June 30, 2023.~~March 31, 2024. See Part I, Item 1 – Financial Statements, Note 56 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of ~~June 30, 2023~~March 31, 2024 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our ~~2022~~2023 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

Dividends

~~On April 28, 2023, our~~Our Board of Directors declared ~~a quarterly~~the following cash ~~dividend~~dividends in each 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.~~periods presented.

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.


	Total Dividend		Rate Per Share
	(in millions)		($ per share)

Three months ended March 31, 2024	$	21	$	0.31




Three months ended March 31, 2023	$	20	$	0.2825

In addition to dividends declared, we paid $4 million of dividend equivalents related to stock-based compensation awards which were settled in the three months ended March 31, 2024. 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. Since the adoption of our dividend policy in 2021, we have returned $175 million to shareholders through dividends. For information regarding past dividends paid, see Cash Flow Analysis, Cash Flow Used in Financing Activities above.

Share Repurchase Program

Our Board of Directors has authorized a Share Repurchase Program to acquire up to ~~$1.1~~$1.35 billion of our common stock through ~~June 30,~~December 31, 2025. The aggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $691 million, excluding commissions and excise taxes on repurchases, as of March 31, 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 a summary of our share repurchases, which are held as treasury stock, for the periods presented:


	Total Number of Shares Purchased	Total Value of Shares Purchased		Average Price Paid per Share
	(number of shares)	(in millions)		($ per share)
Three months ended March 31, 2023	1,423,764	$	59	$	41.25
Three months ended March 31, 2024	1,065,764	$	58	$	53.26




Inception of Program (May 2021) through March 31, 2024	15,929,679	$	662	$	41.39

Divestitures and Acquisitions

See Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions for information on our transactions during the three ~~and six~~ months ended ~~June 30, 2023~~March 31, 2024 and ~~2022.~~2023.

Lawsuits, Claims, Commitments and Contingencies

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at ~~June 30, 2023~~March 31, 2024 and December 31, ~~2022~~2023 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 45 Lawsuits, Claims, Commitments and Contingencies for further information.

Critical Accounting Estimates and Significant Accounting and Disclosure Changes

There have been no changes to our critical accounting estimates, which are summarized in Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates of our ~~2022~~2023 Annual Report.

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Forward-Looking Statements

This document contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” ~~“opportunity” or~~“opportunity,” “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. Additionally, the information in this report contains forward-looking statements related to the pending Aera Merger.

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

•fluctuations in commodity prices, including supply and demand considerations for our products and services;

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

•government policy, war and political conditions and events, including the ~~war~~military conflicts in Israel, Ukraine and ~~oil sanctions~~Yemen and the Red Sea;

•the ability to successfully integrate the business of Aera once the Aera merger is completed;

•the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the Aera merger that could reduce anticipated benefits or cause the parties to abandon the Aera merger;

•the occurrence of any event, change or other circumstances that could give rise to the termination of the Merger Agreement;

•the possibility that the stockholders of CRC may not approve the issuance of new shares of common stock in the Aera merger;

•the ability to obtain the required debt financing pursuant to our commitment letters and, if obtained, the potential impact of additional debt on ~~Russia, Iran~~our business and ~~others;~~the financial impacts and restrictions due to the additional debt;

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

the transportation, marketing and sale of our products;

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

•changes in business strategy and our capital plan;

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

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

•the recoverability of resources and unexpected geologic conditions;

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

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

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

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

•any failure of risk management;

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

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

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

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

•reorganization or restructuring of our operations;

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

•our ability to realize the benefits contemplated by our energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;

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

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

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

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

gather and verify emissions data and other environmental impacts;

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

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

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

•changes in interest rates;

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

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

•effects of hedging transactions;

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

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

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

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

•other factors discussed in Part I, Item 1A – Risk Factors in our ~~2022~~2023 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.

4239

Item 3Quantitative and Qualitative Disclosures About Market Risk

For the three ~~and six~~ months ended ~~June 30, 2023,~~March 31, 2024, there were no material changes to market risks from the information provided under Item 305 of Regulation S-K included under the caption Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk in the ~~2022~~2023 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 ~~June 30, 2023,~~March 31, 2024, we had a net liability of ~~$18~~$49 million for our commodity derivative positions which are carried at fair value. For more information on our derivative positions as of ~~June 30, 2023~~March 31, 2024, refer to Part I, Item 1 – Financial Statements, Note 56 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 ~~June 30, 2023,~~March 31, 2024, the majority of our credit exposure was with investment-grade counterparties. We believe exposure to counterparty credit-related losses related to our business at ~~June 30, 2023~~March 31, 2024 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

Interest-Rate Risk

Changes in interest rate may affect the amount of interest we pay on our long-term debt. We had no variable-rate debt outstanding as of ~~June 30, 2023~~March 31, 2024. Our Senior Notes bear interest at a fixed rate of 7.125% per annum.

Item 4Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer supervised and participated in management's evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of ~~June 30, 2023.~~March 31, 2024.

There were no changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the three months ended ~~June 30, 2023~~March 31, 2024 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

4340

PART II OTHER INFORMATION

Item 1Legal Proceedings

For additional information regarding legal proceedings, see Item 1 – Financial Statements, Note 45 Lawsuits, Claims, Commitments and Contingencies in the Notes to the Condensed Consolidated Financial Statements included in Part I of this Form 10-Q, Part I, Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Lawsuits, Claims, Commitments and Contingencies in this Form 10-Q, and Part I, Item 3, Legal Proceedings in our ~~2022~~2023 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 ~~2022~~2023 Annual ~~Report and our Quarterly Report on Form 10-Q for the three months ended March 31, 2023. Except as set forth below, there~~Report. There were no material changes to those risk factors during the three months ended ~~June 30, 2023.~~

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 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 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 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 operations in the Wilmington Oil Field would result in a decrease in production and reserves from the field.

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 or the 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 techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans~~" in our 2022 Annual Report.~~March 31, 2024.

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds

Our Board of Directors has authorized a Share Repurchase Program to acquire up to ~~$1.1~~$1.35 billion of our common stock through ~~June 30, 2024.~~December 31, 2025. The repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend or discontinue authorization of the program at any time. Shares repurchased are held as treasury stock.

Our share repurchase activity for the three months ended ~~June 30, 2023~~March 31, 2024 was as follows:

Period Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
Maximum Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(a)
April 1, 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 $ —


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(a)
January 1, 2024 - January 31, 2024	—	$	—	—	$	—
February 1, 2024 - February 29, 2024	—	$	—	—	—
March 1, 2024 - March 31, 2024	1,065,764	$	53.26	1,065,764	—
Total	1,065,764	$	53.26	1,065,764	$	—

(a)The total value of shares that may yet be purchased under the Share Repurchase Program totaled ~~$517~~$691 million as of ~~June 30, 2023.~~March 31, 2024.

Item 5 Other Disclosures

Rule 10b5-1 Trading Arrangements

~~As previously disclosed, on June 16, 2023, Omar Hayat was appointed to~~

During 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)three months ended March 31, 2024, none of our directors or officers adopted or terminated a ~~base salary~~“Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 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.Regulation S-K.

4641

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			Agreement and Plan of Merger, dated February 7, 2024, among California Resources Corporation and Petra Merger Sub I, LLC, Petra Merger Sub C, LLC, Petra Merger Sub O, LLC, Petra Merger Sub O2, LLC, Petra Merger Sub O3, LLC, each a Delaware limited liability company and a wholly-owned direct subsidiary of the Company, Petra Merger Sub S, LLC, a Delaware limited liability company and a wholly-owned direct subsidiary of the Company, IKAV Impact USA Inc., a Delaware corporation, CPPIB Vedder US Holdings LLC, a Delaware limited liability company, Opps Xb Aera E CTB, LLC, a Delaware limited liability company, Opps XI Aera E CTB, LLC, a Delaware limited liability company, Green Gate COI, LLC, a Delaware limited liability company and solely for purposes of the Member Provisions (as defined in the Merger Agreement), IKAV Impact S.a.r.l., a Luxembourg corporation, Simlog Inc., a Delaware corporation, and IKAV Energy Inc., a Delaware corporation, CPP Investment Board Private Holdings (6), Inc., a Canadian corporation, OCM Opps Xb AIF Holdings (Delaware), L.P., a Delaware limited partnership, Oaktree Huntington Investment Fund II AIF (Delaware), L.P. – Class C, a Delaware limited partnership, OCM Opps XI AIV Holdings (Delaware), L.P., a Delaware limited partnership and OCM Aera E Holdings, LLC, a Delaware limited liability company. (filed as Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed February 9, 2024 and incorporated herein by reference).

10.2			Second Amendment to the Amended and Restated Credit Agreement, ~~dated~~entered into effective as of ~~April 26, 2023,~~February 2, 2024, 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~~10.1 to the ~~Registrant’s Quarterly~~Registrant's Current Report on Form ~~10-Q~~8-K filed ~~on May 4, 2023~~February 14, 2024 and incorporated herein by reference).

10.2**10.3			~~Employment~~T hird Amendment to the Amended and Restated Credit Agreement, entered into effective as of Ma rch 8 , 2024 , by and ~~between Manuela Molina and~~among California Resources Corporation, ~~dated May 8, 2023~~as the Borrower , the several lenders from time to time parties thereto and Citibank, N.A., as A dministrative Agent (filed as ~~Exhibit~~ Exh ibit 10.1 to the ~~Registrant's~~ R egistrant's Current Report on Form 8-K filed on M ay 1 ~~, 2023~~March 11, 2024 and incorporated herein by reference ).

10.3,*10.4			~~Employment Agreement by and between Omar Hayat and~~2024 Form of California Resources Corporation ~~dated July 27, 2023.~~2021 Long Term Incentive Restricted Stock Unit Award Term and Conditions (filed as Exhibit 10.29 to the Registrant’s Annual Report on Form 10-K filed on February 28, 2024 and incorporated herein by reference).

10.4,*10.5			~~Amended and Restated~~ ~~Employment Agreement by and between Christopher D. Gould and~~2024 Form of California Resources Corporation ~~dated July 27, 2023.~~2021 Long Term Incentive Plan Performance Stock Unit Award Term and Conditions (filed as Exhibit 10.30 to the Registrant’s Annual Report on Form 10-K filed on February 28, 2024 and incorporated herein by reference).

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

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

32.1*			Certifications of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*			Inline XBRL Instance Document.

101.SCH*			Inline XBRL Taxonomy Extension Schema Document.

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

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

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

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

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

* - Filed or furnished herewith

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

4743

SIGNATURES

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


			CALIFORNIA RESOURCES CORPORATION


DATE:	~~August 1, 2023~~May 8, 2024	/s/ Noelle M. Repetti
		Noelle M. Repetti
		Senior Vice President and Controller
		(Principal Accounting Officer)

4844


	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


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

Share-based compensation	—		—		3		—		—		3



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

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

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


	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


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)