CRC 10-Q Quarterly Report Sept. 30, 2024

CALIFORNIA RESOURCES CORP

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crc-20240930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 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 Corp oration

(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 October 31, 2024 was 91,705,360 .

California Resources Corporation and Subsidiaries

Table of Contents


	Page
Part I
Item 1	Financial Statements (unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements of Comprehensive Income (Loss)	6
	Condensed Consolidated Statements of Stockholders' Equity	7
	Condensed Consolidated Statements of Cash Flows	9
	Notes to the Condensed Consolidated Financial Statements	10
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
	General	34
	Aera Merger	34
	Recent Debt Transactions	34
	Business Environment and Industry Outlook	35
	Regulatory Updates	37
	Results of Oil and Gas Operations	38
	Statements of Operations Analysis	44
	Liquidity and Capital Resources	52
	Divestitures, Acquisitions and Assets Held for Sale	57
	Lawsuits, Claims, Commitments and Contingencies	57
	Critical Accounting Estimates and Significant Accounting and Disclosure Changes	58
	Forward-Looking Statements	59
Item 3	Quantitative and Qualitative Disclosures About Market Risk	61
Item 4	Controls and Procedures	61

Part II
Item 1	Legal Proceedings	62
Item 1A	Risk Factors	62
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 5	Other Disclosures	63
Item 6	Exhibits	64

GLOSSARY AND SELECTED ABBREVIATIONS

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

• ABR - Alternate base rate.

• Aera - Aera Energy, LLC.

• Aera Merger - The transactions contemplated by the Merger Agreement.

• 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.

• Brookfield - BGTF Sierra Aggregator LLC.

• Btu - British thermal unit.

• CalGEM - California Geologic Energy Management Division.

• Carbon TerraVault JV - A joint venture between our wholly-owned subsidiary Carbon TerraVault I, LLC with Brookfield for the further development of a carbon management business in California.

• CCS - Carbon capture and storage.

• CDMA - Carbon Dioxide Management Agreement.

• CEQA - California Environmental Quality Act.

• CO 2 - 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.

• GAAP - United States Generally Accepted Accounting Principles.

• G&A - General and administrative expenses.

• GHG - Greenhouse gases.

• JV - Joint venture.

• LCFS - Low Carbon Fuel Standard.

• 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.

• Merger Agreement - Definitive agreement and plan of merger related to the transactions to obtain all of the ownership interests in Aera.

• 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 - Contractual arrangements similar to 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 1 Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of September 30, 2024 and December 31, 2023

(in millions, except share data)


	September 30,		December 31,
	2024		2023
CURRENT ASSETS
Cash and cash equivalents	$	241	$	496
Trade receivables	313		216
Inventories	75		72
Assets held for sale	13		13
Receivable from affiliate	46		19
Other current assets, net	184		113
Total current assets	872		929
PROPERTY, PLANT AND EQUIPMENT	6,752		3,437
Accumulated depreciation, depletion and amortization	( 916 )		( 667 )
Total property, plant and equipment, net	5,836		2,770
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	84		19
DEFERRED INCOME TAXES	50		132
OTHER NONCURRENT ASSETS	286		148
TOTAL ASSETS	$	7,128	$	3,998


CURRENT LIABILITIES



Accounts payable	351		245
Liabilities associated with assets held for sale	5		5

Accrued liabilities	541		366

Total current liabilities	897		616
NONCURRENT LIABILITIES
Long-term debt, net	1,131		540
Fair value of derivative contracts	55		2
Asset retirement obligations	1,083		422
Deferred tax liability	124		—
Other long-term liabilities	337		199



STOCKHOLDERS' EQUITY
Preferred stock ( 20,000,000 shares authorized at $ 0.01 par value) no shares outstanding at September 30, 2024 and December 31, 2023	—		—
Common stock ( 200,000,000 shares authorized at $ 0.01 par value) ( 106,930,510 and 83,557,800 shares issued; 89,461,673 and 68,693,885 shares outstanding at September 30, 2024 and December 31, 2023)	1		1
Treasury stock ( 17,468,837 shares held at cost at September 30, 2024 and 14,863,915 shares held at cost at December 31, 2023)	( 739 )		( 604 )
Additional paid-in capital	2,479		1,329
Retained earnings	1,683		1,419
Accumulated other comprehensive income	77		74


Total stockholders' equity	3,501		2,219
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	7,128	$	3,998

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

CALIFORNIA R ESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

For the three and nine months ended September 30, 2024 and 2023

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


	Three months ended September 30,				Nine months ended September 30,
	2024		2023		2024		2023
REVENUES
Oil, natural gas and NGL sales	$	870	$	510	$	1,711	$	1,672
Net gain (loss) from commodity derivatives	356		( 204 )		290		( 131 )
Revenue from marketing of purchased commodities	51		77		176		336
Electricity sales	69		67		120		169
Interest and other revenue	7		10		24		29
Total operating revenues	1,353		460		2,321		2,075

OPERATING EXPENSES
Operating costs	311		196		643		636
General and administrative expenses	106		65		226		201
Depreciation, depletion and amortization	140		56		246		170
Asset impairment	—		—		13		3
Taxes other than on income	85		48		162		132
Exploration expense	1		—		2		2
Costs related to marketing of purchased commodities	43		31		140		182
Electricity generation expenses	9		23		31		85
Transportation costs	23		16		60		49
Accretion expense	31		12		56		35
Carbon management business expenses	13		7		36		20
Other operating expenses, net	73		21		161		42
Total operating expenses	835		475		1,776		1,557
Gain on asset divestitures	—		—		7		7

OPERATING INCOME (LOSS)	518		( 15 )		552		525

NON-OPERATING (EXPENSES) INCOME

Interest and debt expense	( 29 )		( 15 )		( 59 )		( 43 )
Loss on early extinguishment of debt	( 5 )		—		( 5 )		—
Loss from investment in unconsolidated subsidiaries	( 2 )		( 3 )		( 9 )		( 6 )
Other non-operating income (loss)	1		3		( 4 )		5
INCOME (LOSS) BEFORE INCOME TAXES	483		( 30 )		475		481
Income tax (provision) benefit	( 138 )		8		( 132 )		( 105 )
NET INCOME (LOSS)	$	345	$	( 22 )	$	343	$	376






Net income (loss) per share
Basic	$	3.86	$	( 0.32 )	$	4.54	$	5.38
Diluted	$	3.78	$	( 0.32 )	$	4.42	$	5.18

Weighted-average common shares outstanding
Basic	89.4		68.7		75.5		69.9
Diluted	91.2		68.7		77.6		72.6

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Comprehensive Income (Loss)

For the three and nine months ended September 30, 2024 and 2023

(in millions)


	Three months ended September 30,				Nine months ended September 30,
	2024		2023		2024		2023
Net income (loss)	$	345	$	( 22 )	$	343	$	376
Other comprehensive income (loss) (a) :
Actuarial gain associated with pension and postretirement plans	9		—		9		—
Amortization of prior service cost credit included in net periodic benefit cost, net of tax	( 4 )		( 5 )		( 6 )		( 5 )
Comprehensive income (loss)	$	350	$	( 27 )	$	346	$	371

(a) Amounts are net of $ 2 million and $ 1 million in tax for the three and nine months ended September 30, 2024, respectively. Amounts are net of $ 2 million in tax for the three and nine months ended September 30, 2023.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Stockholders' Equity

For the three and nine months ended September 30, 2024 and 2023

(in millions)


	Three months ended September 30, 2024
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, June 30, 2024	$	1	$	( 697 )	$	1,302	$	1,374	$	72	$	2,052
Net income	—		—		—		345		—		345

Share-based compensation	—		—		5		—		—		5


Repurchases of common stock	—		( 42 )		—		—		—		( 42 )
Shares issued for warrants	—		—		37		—		—		37
Shares issued for Aera Merger	—		—		1,135		—		—		1,135

Cash dividend ($ 0.3875 per share)	—		—		—		( 36 )		—		( 36 )


Other comprehensive income, net of tax	—		—		—		—		5		5
Balance, September 30, 2024	$	1	$	( 739 )	$	2,479	$	1,683	$	77	$	3,501


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

Share-based compensation	—		—		8		—		—		8



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

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

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


	Nine months ended September 30, 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 income	—		—		—		343		—		343



Share-based compensation	—		—		19		—		—		19


Repurchases of common stock	—		( 135 )		—		—		—		( 135 )

Shares issued for warrants	—		—		37		—		—		37
Shares issued for Aera Merger	—		—		1,135		—		—		1,135
Cash dividend ($ 1.0075 per share)	—		—		—		( 79 )		—		( 79 )
Shares cancelled for taxes					( 42 )		—		—		( 42 )
Other comprehensive income, net of tax	—		—		—		—		3		3
Other	—		—		1		—		—		1
Balance, September 30, 2024	$	1	$	( 739 )	$	2,479	$	1,683	$	77	$	3,501


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



Share-based compensation	—		—		22		—		—		22
Repurchases of common stock	—		( 143 )		—		—		—		( 143 )


Cash dividend ($ 0.8475 per share)	—		—		—		( 61 )		—		( 61 )
Shares cancelled for taxes					( 3 )		—		—		( 3 )

Other comprehensive income, net of tax	—		—		—		—		( 5 )		( 5 )

Balance, September 30, 2023	$	1	$	( 604 )	$	1,324	$	1,253	$	76	$	2,050

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

For the three and nine months ended September 30, 2024 and 2023

(in millions)


	Three months ended September 30,				Nine months ended September 30,
	2024		2023		2024		2023
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)	$	345	$	( 22 )	$	343	$	376
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	140		56		246		170
Deferred income tax provision (benefit)	90		( 40 )		84		16
Asset impairments	—		—		13		3
Net (gain) loss from commodity derivatives	( 347 )		204		( 279 )		131
Net payments on settled commodity derivatives	( 29 )		( 95 )		( 53 )		( 223 )
Net loss on early extinguishment of debt	5		—		5		—

Gain on asset divestitures	—		—		( 7 )		( 7 )



Other non-cash charges to income, net	45		26		97		77
Changes in operating assets and liabilities, net	( 29 )		( 25 )		( 45 )		( 21 )
Net cash provided by operating activities	220		104		404		522

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	( 79 )		( 33 )		( 167 )		( 119 )
Changes in accrued capital investments	6		5		8		( 10 )
Proceeds from asset divestitures, net	—		—		12		—
Purchase of a business, net of cash acquired	( 853 )		—		( 853 )		—
Acquisitions	—		—		( 6 )		( 1 )


Other, net	( 2 )		—		( 4 )		( 3 )
Net cash used in investing activities	( 928 )		( 28 )		( 1,010 )		( 133 )

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from Revolving Credit Facility	—		—		30		—
Repayments of Revolving Credit Facility	( 30 )		—		( 30 )		—
Proceeds from 2029 Senior Notes, net	298		—		888		—

Repurchases of common stock	( 42 )		( 20 )		( 135 )		( 143 )
Common stock dividends	( 34 )		( 19 )		( 77 )		( 59 )
Payments on equity-settled awards	—		—		( 4 )		—




Issuance of common stock	—		—		2		1
Bridge loan commitments	—		—		( 5 )		—
Debt amendment costs	( 7 )		—		( 10 )		( 8 )
Stock warrants exercised	37		—		37		—
Shares cancelled for taxes	—		( 1 )		( 42 )		( 3 )
Debt repurchases	( 303 )		( 5 )		( 303 )		( 5 )
Other	( 1 )		—		—		—
Net cash (used in) provided by financing activities	( 82 )		( 45 )		351		( 217 )
Increase (decrease) in cash and cash equivalents	( 790 )		31		( 255 )		172
Cash and cash equivalents—beginning of period	1,031		448		496		307
Cash and cash equivalents—end of period	$	241	$	479	$	241	$	479

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

September 30, 2024

NOTE 1 BASIS OF PRESENTATION

We are an independent energy and carbon management company committed to energy transition. We are committed to environmental stewardship while safely providing local, responsibly sourced energy. We are also focused on maximizing the value of our land, mineral ownership, and energy expertise for decarbonization by developing carbon capture and storage (CCS) and other emissions-reducing projects.

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 as of the date presented.

In the opinion of our management, the accompanying unaudited condensed consolidated 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 investments in our unconsolidated subsidiaries are recognized either at cost, as is the case with Carbon TerraVault JV HoldCo, LLC, or at fair value if acquired in a business combination, as is the case for Midway Sunset Cogeneration Company. These investments are 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.

On July 1, 2024, we closed on transactions pursuant to the definitive agreement and plan of merger (Merger Agreement) to obtain all of the ownership interests in Aera Energy, LLC (Aera) (Aera Merger). Refer to Note 2 Aera Merger for further discussion of the Aera Merger. The Aera Merger has been accounted for as a business combination in accordance with Accounting Standards Codification Topic 805, Business Combinations (ASC 805). The merger consideration of $ 2.1 billion was allocated to individual assets acquired net of liabilities assumed based on their fair value as of July 1, 2024 and are not included on the comparative balance sheet presented. The accompanying unaudited condensed consolidated statement of operations, comprehensive income and cash flows contain the results of Aera beginning on July 1, 2024.

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, 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 4 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 and nine months ended September 30, 2023, we reclassified $ 1 million and $ 2 million, respectively, related to NGL storage activities from other revenue to revenue from marketing of purchased commodities on our condensed consolidated statement of operations.

Concentration of Customers

We sell crude oil, natural gas and NGLs to marketers, California refineries and other customers that have access to transportation and storage facilities. In light of the ongoing energy deficit in California and strong demand for native crude oil production, we do not believe that the loss of any single customer would have a material adverse effect on our consolidated financial statements taken as a whole.

For the three months ended September 30, 2024, two California customers each accounted for at least 10%, and collectively 58 %, of our sales (before the effects of hedging).

NOTE 2 AERA MERGER

On July 1, 2024, we obtained by way of merger all of the ownership interests in Aera. Aera is a leading operator of mature fields in California, primarily in the San Joaquin and Ventura basins, with high oil-weighted production. The Aera Merger adds significant proved developed reserves to CRC. In connection with the closing of the Aera Merger, we issued 21,315,707 shares of common stock to the former Aera owners (Sellers). We also paid approximately $ 990 million in connection with the extinguishment of all of Aera's outstanding indebtedness using the proceeds from the issuance of our 8.25 % senior notes due 2029 (2029 Senior Notes) and cash on hand. For more information on the 2029 Senior Notes and recent amendments to our Revolving Credit Facility, refer to Note 4 Debt and Note 15 Subsequent Events.

As of July 1, 2024, and immediately following closing of the Aera Merger, our existing stockholders prior to the Aera Merger owned 76 % of CRC and the Sellers owned 24 % of CRC.

At the date of this filing, our assessment of the fair value of assets acquired and liabilities assumed is not complete. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, final appraisals of Aera's assets, evaluation of Aera's materials and supplies inventory, measurement of leases and preparation of final tax returns that will provide underlying tax basis of the assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period subsequent to the Aera Merger closing date and adjustments may be made to the provisional amounts recorded as of September 30, 2024.

The following table summarizes the consideration transferred:


	Merger Consideration
	(in millions, except share and per share data)
Shares of common stock (dividend adjusted)	21,315,707
Common stock per share fair value on July 1, 2024	$	53.28
Fair value of share consideration	$	1,136
Settlement of Aera debt	990
Member taxes	( 1 )
Total purchase consideration	$	2,125

The following table represents the preliminary purchase price allocation of the identifiable assets acquired and the liabilities assumed based on their estimated fair values as of the closing date of the Aera Merger:


	Preliminary Purchase Price Allocation
	(in millions)
Assets Acquired
Cash	$	137
Other current assets	202
Investment in unconsolidated subsidiary	59
Property, plant and equipment	3,119
Pension and other postretirement benefits	73
Other noncurrent assets	67
Total Assets Acquired	3,657

Liabilities Assumed
Accounts payable	( 157 )
Accrued liabilities	( 132 )
Asset retirement obligations	( 700 )
Fair value of derivative contracts	( 351 )
Other long-term liabilities	( 192 )
Total Liabilities Assumed	( 1,532 )
Net Assets Acquired	$	2,125

We recorded cash based on Aera's bank balances as of July 1, 2024, which included restricted cash of $ 27 million. The measurements for predominately all of the other current and other noncurrent assets acquired and accounts payable, accrued liabilities and other long-term liabilities assumed are based on contracts in place at Aera on the acquisition date. Assets and liabilities related to Aera's pension and other postretirement benefit plans were measured based on actuarial valuations using Level 3 inputs. For more information on Aera's pension and other postretirement benefit plans, see Note 11 Pension and Postretirement Benefit Plans .

The fair value of an investment in an unconsolidated subsidiary was based on a preliminary appraisal using both the cost approach and available market data. The fair value of derivative instruments was based on observable inputs, primarily forward commodity-price curves. These inputs are considered Level 2 inputs in the fair value hierarchy.

The fair value of certain acquired property, plant and equipment, primarily consisting of proved oil and natural gas properties, land, gas processing plants and corporate assets including software and computer equipment, was based on preliminary appraisals. The fair value of proved oil and natural gas properties as of the acquisition date is based on estimated discounted future net cash flows incorporating market participant assumptions on an after-tax basis. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, a weighted average cost of capital and a projected inflation rate. When estimating the fair value of proved properties, additional risk adjustments were applied to proved undeveloped reserves to reflect the relative uncertainty of the reserve class. These inputs are classified as Level 3 unobservable inputs, including the underlying commodity price assumptions which are based on the five-year NYMEX forward strip prices, escalated for inflation thereafter, and adjusted for price differentials.

The liability for future asset retirement obligations was determined by calculating the present value of estimated future abandonment costs. We utilized several assumptions, including a credit-adjusted risk-free interest rate, estimated remediation costs, estimated timing of when the work will be performed and a projected inflation rate.

Deferred income taxes, included in other noncurrent assets and long-term liabilities, represent the tax effects of differences in the tax basis and merger-date fair values of assets acquired and liabilities assumed. Refer to Note 7 Income Taxes for additional information on the deferred tax liability.

Lease-related assets and liabilities acquired are remeasured as if the leases were new at the merger date. These agreements are still under review for measurement at an updated incremental borrowing rate. Lease assets are included in property, plant and equipment and the liabilities are included in accrued liabilities and other long-term liabilities.

Supplemental Unaudited Pro Forma Financial Information

The following supplemental unaudited pro forma financial information presents the condensed consolidated results of operations for the three and nine months ended September 30, 2024 and 2023 as if the Aera Merger had occurred on January 1, 2023.


	Three months ended September 30,				Nine months ended September 30,
	2024		2023		2024		2023

	(in millions)				(in millions)
Total operating revenue	$	1,353	$	438	$	3,006	$	3,165
Net income	$	386	$	( 459 )	$	341	$	43

EPS
Basic	$	4.32	$	( 5.10 )	$	3.53	$	0.47
Diluted	$	4.23	$	( 5.10 )	$	3.45	$	0.45

The pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the Aera Merger been completed on January 1, 2023, nor is it necessarily indicative of future operating results of the combined entity. The pro forma financial information for the three and nine months ended September 30, 2024 and 2023 is a result of combining our three and nine months statements of operations with Aera's pre-merger results from January 1, 2024 and 2023 and includes adjustments for revenues and direct expenses. The pro forma results do not reflect any cost savings anticipated as a result of the Aera Merger and exclude the impact of any severance and merger-related costs. The pro forma results include adjustments to depreciation, depletion and amortization (DD&A) based on the purchase price allocated to property, plant, and equipment and the estimated useful lives as well as adjustments to interest and accretion expense. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the Aera Merger are properly reflected. Future results may vary significantly from the results reflected in the following pro forma information.

For the period of July 1, 2024 through September 30, 2024, revenue and income before income taxes associated with Aera totaled $ 765 million and $ 400 million, respectively.

The following table summarizes the merger-related costs incurred:


	Three months ended September 30, 2024		Nine months ended September 30, 2024

	(in millions)
Employee severance and related costs	$	27	$	28
Transaction and integration costs	$	30	$	56
Total merger-related costs	$	57	$	84

Transaction and integration costs related to the Aera Merger and employee severance and related costs are included in other operating expenses, net on our condensed consolidated statement of operations.

In August 2024, management committed to a reduction in force as part of the integration process following the Aera Merger, which, when complete, will result in a 12 % reduction in the combined company's employee headcount. We initiated this workforce reduction to align the size and composition of our workforce with expected future operating and capital plans. In addition, employee severance and related costs includes expenses from a voluntary separation program for eligible employees.

The accelerated vesting of certain awards for former Aera executives was $ 7 million, and is included in general and administrative expenses for the three and nine months ended September 30, 2024. This amount for accelerated vesting is not included in the table above. The accelerated vesting was based on existing change of control provisions within the former Aera employee award agreements.

NOTE 3 INVESTMENT IN UNCONSOLIDATED SUBSIDIARIES AND RELATED PARTY TRANSACTIONS

Midway Sunset Cogeneration Company

In July 2024, our merger with Aera led to our ownership of Midway Sunset Cogeneration Company, which is a partnership designed to own, manage, and operate a cogeneration facility in Kern County, California. We hold a 50 % interest in Midway Sunset Cogeneration Company and San Joaquin Energy Company, a subsidiary of NRG Energy Inc. (NRG), holds a 50 % interest. We determined that Midway Sunset Cogeneration Company is a voting interest entity, where we share decision-making power with San Joaquin Energy Company, on all matters that most significantly impact the economic performance of the company. Therefore, we account for our investment in Midway Sunset Cogeneration Company under the equity method of accounting. We recorded our investment at a preliminary fair value of $ 59 million which was $ 48 million in excess of Aera's investment in the underlying assets of the partnership. This difference is associated with PP&E and we expect this amount will reverse over the remaining useful life of the power plant. There are no significant transactions between CRC and Midway Sunset Cogeneration Company. As of September 30, 2024, the carrying value of our investment in Midway Sunset Cogeneration Company was $ 55 million.

Carbon TerraVault JV

In August 2022, we entered into a joint venture with BGTF Sierra Aggregator LLC (Brookfield) for the further development of a carbon management business in California (Carbon TerraVault JV). 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 committed an initial $ 500 million to invest in CCS projects that are jointly approved through the Carbon TerraVault JV. Our initial contribution included rights to inject CO 2 into the 26R reservoir in our Elk Hills field for permanent CO 2 storage (26R reservoir). Brookfield's initial investment is $ 137 million, of which $ 92 million has been contributed to date. The remaining amount of Brookfield's initial investment will be sized based on permitted storage capacity.

Because the parties have certain put and call rights (repurchase features) with respect to the 26R reservoir if certain milestones are not met, the initial investment by Brookfield is reflected as a contingent liability included in other long-term liabilities on our condensed consolidated balance sheets. The contingent liability was $ 104 million and $ 52 million at September 30, 2024 and December 31, 2023 , respectively, inclusive of interest.

The tables below present the summarized financial information related to our equity method investment 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.



	September 30,		December 31,
	2024		2023

	(in millions)
Investment in unconsolidated subsidiary	$	29	$	19
Receivable from affiliate (a)	$	46	$	19
Other long-term liabilities - Contingent liability (related to Carbon TerraVault JV put and call rights)	$	104	$	52

(a) 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 September 30, 2024 , the amount of $ 46 million includes the remaining $ 43 million of Brookfield's first and second installments of their initial investment which is available to us and $ 3 million related to the MSA and vendor reimbursements. At December 31, 2023 , the amount of $ 19 million includes $ 17 million remaining of Brookfield's initial contribution available to us and $ 2 million related to the MSA and vendor reimbursements.


	Three months ended September 30,				Nine months ended September 30,
	2024		2023		2024		2023

	(in millions)				(in millions)
Loss from investment in unconsolidated subsidiary	$	3	$	3	$	10	$	6
General and administrative expenses (a)	$	2	$	2	$	7	$	5

(a) General and administrative expenses on our condensed consolidated statements of operations have been reduced by this amount which we have invoiced to the Carbon TerraVault JV under the MSA for back-office operational and commercial services.

We are also performing well abandonment work at our Elk Hills field as part of the permitting process for injection of CO 2 at the 26R reservoir. During the three and nine months ended September 30, 2024, we performed abandonment work and sought reimbursement in the amounts of $ 4 million and $ 13 million, respectively, from the Carbon TerraVault JV. During the three and nine months ended September 30, 2023, we performed abandonment work and sought reimbursement in the amounts of $ 2 million and $ 4 million, respectively, from the Carbon TerraVault JV.

NOTE 4 DEBT

As of September 30, 2024 and December 31, 2023, our long-term debt consisted of the following:



	September 30,		December 31,
	2024		2023		Interest Rate	Maturity

	(in millions)

Revolving Credit Facility	$	—	$	—	SOFR plus 2.50 %- 3.50 % ABR plus 1.50 %- 2.50 % (a)	July 31, 2027 (b)

2026 Senior Notes	245		545		7.125 %	February 1, 2026
2029 Senior Notes	900		—		8.250 %	June 15, 2029
Principal amount	$	1,145	$	545
Unamortized debt discount and issuance costs	( 17 )		( 5 )
Unamortized premium	3		—
Long-term debt, net	$	1,131	$	540

(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 a 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) On November 1, 2024 the maturity date of the Revolving Credit Facility was extended to March 16, 2029, and the springing maturity date was also amended. See Note 15 Subsequent Events for more information on the amendment.

Revolving Credit Facility

As of September 30, 2024, our Amended and Restated Credit Agreement, dated April 26, 2023 (Revolving Credit Facility), consisted of a senior revolving loan facility with an aggregate commitment of $ 1.1 billion. The amount we are able to borrow under our Revolving Credit Facility is limited to the amount of these commitments. Our Revolving Credit Facility also included a sub-limit of $ 250 million for the issuance of letters of credit. As of September 30, 2024, $ 175 million letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters. As of September 30, 2024, we had $ 925 million of availability on our Revolving Credit Facility after taking into account $ 175 million in letters of credit outstanding. Our borrowing base of $ 1.5 billion is redetermined semi-annually and was re-affirmed in November 2024 as part of our recent amendment. For information on the fifth amendment to our Revolving Credit Facility, refer to Note 15 Subsequent Events.

Amendments

In February 2024, in connection with the Aera Merger, we entered into a second amendment to our Revolving Credit Facility to, among other things, permit the incurrence of indebtedness under a bridge loan facility. We did not utilize a bridge loan facility in connection with the Aera Merger and wrote-off $ 6 million of bridge loan and commitment fees during the three months ended June 30, 2024 included in other non-operating (loss) income on our condensed consolidated statement of operations. We capitalized approximately $ 3 million in deferred financing fees related to this amendment to other assets on our condensed consolidated statement of financial position during the nine months ended September 30, 2024. We did not capitalize any deferred financing fees related to this amendment during the three months ended September 30, 2024.

In March 2024, we entered into a third amendment to our Revolving Credit Facility. This amendment facilitated certain matters with respect to the Aera Merger, including the postponement of the regular spring borrowing base redetermination until the fall of 2024 and certain other amendments.

In July 2024, we entered into a fourth amendment to our Revolving Credit Facility as part of the Aera Merger. This amendment increased the aggregate revolving commitments available under the Revolving Credit Facility from $ 630 million to $ 1.1 billion. Our ability to borrow under our Revolving Credit Facility is limited to the amount of these commitments. This amendment also increased the borrowing base from $ 1.2 billion to $ 1.5 billion, among other matters. We capitalized approximately $ 7 million in deferred financing fees related to this amendment to other assets on our condensed consolidated statement of financial position during the three and nine months ended September 30, 2024.

On November 1, 2024, we entered into a fifth amendment to our Revolving Credit Facility which included extending the springing maturity of our Revolving Credit Facility and increasing the aggregate amount of our commitments by $ 50 million. Refer to Note 15 Subsequent Events for additional information on the fifth amendment.

2029 Notes Offering and Follow-On Offering

On June 5, 2024, we completed the offering of $ 600 million in aggregate principal amount of the 2029 Senior Notes. The terms of the 2029 Senior Notes are governed by the indenture, dated as of June 5, 2024, by and among us, the guarantors and Wilmington Trust, National Association, as trustee (2029 Senior Notes Indenture). The net proceeds of $ 590 million, after $ 10 million of debt discount and issuance costs, were used along with available cash to repay all of Aera's outstanding debt for approximately $ 990 million at closing of the Aera Merger. See Note 2 Aera Merger for more information on the closing of the Aera Merger.

On August 22, 2024, we completed a follow-on offering of an additional $ 300 million in aggregate principal amount of 2029 Senior Notes. The net proceeds from this offering of $ 298 million, after $ 3 million of debt premium and $ 5 million of debt issuance costs, were used to repurchase a portion of our 7.125 % senior notes due 2026 (2026 Senior Notes). The 2029 Senior Notes issued on August 22, 2024 are governed by the same indenture as the $ 600 million of 2029 Senior Notes that were previously issued on June 5, 2024.

Security – Our 2029 Senior Notes are general unsecured obligations which are guaranteed on a senior unsecured basis by all of our existing subsidiaries that guarantee our obligations under the Revolving Credit Facility and our existing 2026 Senior Notes.

Redemption – We may redeem the 2029 Senior Notes at any time on or after June 15, 2026 at the redemption prices of (i) 104.125 % during the twelve-month period beginning on June 15, 2026, (ii) 102.063 % during the twelve-month period beginning on June 15, 2027 and (iii) 100 % after June 15, 2028 and before the maturity date. Prior to June 15, 2026, we may redeem up to 35 % of the aggregate principal amount of the 2029 Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 108.250 %. In addition, before June 15, 2026, we may redeem some or all of the 2029 Senior Notes at a redemption price equal to 100 % of the aggregate principal amount of the 2029 Senior Notes redeemed, plus the applicable premium as specified in the 2029 Senior Notes Indenture and accrued and unpaid interest, if any, to, but excluding, the redemption date.

Other Covenants – Our 2029 Senior Notes include covenants that, among other things, restrict our ability to incur additional indebtedness, issue preferred stock, grant liens, make asset sales and investments, repay existing indebtedness, make subsidiary distributions, and enter into transactions that would result in fundamental changes.

Events of Default and Change of Control – Our 2029 Senior Notes provide for certain triggering events, including upon a change of control, as defined in the indenture, that would require us to repurchase all or any part of the 2029 Senior Notes at a price equal to 101 % of the aggregate principal amount plus accrued and unpaid interest.

Tender Offer and Note Repurchases

In the three and nine months ended September 30, 2024, we repurchased $ 300 million in face value of our 2026 Senior Notes for $ 303 million, resulting in a loss on early extinguishment of debt in the amount of $ 5 million which includes a $ 2 million write-off of unamortized debt issuance costs. In the three and nine months ended September 30, 2023, we repurchased $ 5 million in face value of our 2026 Senior Notes at par, resulting in an insignificant extinguishment loss for the write-off of unamortized debt issuance costs.

Our 2026 Senior Notes are redeemable at any time prior to the maturity date at a redemption price equal to (i) 102 % of the principal amount if redeemed in the twelve months beginning February 1, 2024, and (ii) 100 % of the principal amount if redeemed after February 1, 2025, in each case plus accrued and unpaid interest.

Fair Value

As shown in the table below, we estimate the fair value of our fixed rate 2029 Senior Notes and 2026 Senior Notes based on known prices from market transactions (using Level 1 inputs on the fair value hierarchy).


	September 30,		December 31,
	2024		2023

	(in millions)
Variable rate debt	$	—	$	—
Fixed rate debt
2026 Senior Notes	246		554
2029 Senior Notes	918		—
Fair Value of Long-Term Debt	$	1,164	$	554

Other

As of September 30, 2024, we were in compliance with all financial and other debt covenants under our Revolving Credit Facility, 2026 Senior Notes and 2029 Senior Notes. For more information on our 2026 Senior Notes, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2023 Annual Report.

NOTE 5 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 we determine it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances for these items at September 30, 2024 and December 31, 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. In March 2024, we entered into a cost sharing agreement with former lessees to share in 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 be approximately $ 5 million per year. Due to the preliminary stage of the process, no cost estimates to abandon the offshore platforms have been determined.

As of September 30, 2024 there were no material changes to our legacy purchase obligations disclosed in the 2023 Annual Report. In connection with the Aera Merger, we assumed purchase obligations of approximately $ 50 million. These purchase obligations are primarily related to natural gas transportation and a power purchase agreement for a future solar project.

NOTE 6 DERIVATIVES

We continue to maintain a commodity hedging program primarily focused on crude oil to help protect our cash flows, margins and capital program from the volatility of commodity prices. We also enter into natural gas swaps for the purpose of hedging our fuel consumption in our steamflood operations as well as swaps for natural gas purchases and sales related to our marketing activities. In connection with the Aera Merger, we also acquired swaps related to crude oil sales and natural gas purchases. We did not have any derivative instruments designated as accounting hedges as of and for the three and nine months ended September 30, 2024 and 2023. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to implement our hedging strategy.

Summary of Derivative Contracts

We held the following Brent-based contracts as of September 30, 2024:


	Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025		2026		2027		2028
Sold Calls
Barrels per day	29,000		30,000		30,000		30,000		29,000		5,000		—		—
Weighted-average price per barrel	$	90.07	$	87.08	$	87.08	$	87.08	$	87.13	$	85.00	$	—	$	—

Purchased Puts
Barrels per day	29,000		30,000		30,000		30,000		29,000		5,000		—		—
Weighted-average price per barrel	$	65.17	$	61.67	$	61.67	$	61.67	$	61.72	$	60.00	$	—	$	—

Swaps
Barrels per day	59,014		52,837		45,631		44,126		42,626		30,449		13,882		10,353
Weighted-average price per barrel	$	74.90	$	72.48	$	71.31	$	70.62	$	69.94	$	67.95	$	65.53	$	65.00

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.

At September 30, 2024, we also held the following swaps to hedge purchased natural gas used in our operations as shown in the table below.


	Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025		2026		2027		2028

SoCal Border
MMBtu per day	20,000		10,000		29,074		25,750		22,408		—		—		—
Weighted-average price per MMBtu	$	5.49	$	6.02	$	3.44	$	3.48	$	3.53	$	—	$	—	$	—

NWPL Rockies
MMBtu per day	50,999		50,999		51,750		51,750		51,750		35,336		12,616		9,613
Weighted-average price per MMBtu	$	4.67	$	5.48	$	2.95	$	2.95	$	4.22	$	4.04	$	4.34	$	3.95

PG&E Citygate
MMBtu per day	14,000		14,000		—		—		—		—		—		—
Weighted-average price per MMBtu	$	5.60	$	6.10	$	—	$	—	$	—	$	—	$	—	$	—

We also have a limited number of derivative contracts related to our natural gas marketing activities that 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 below:


	Three months ended September 30,				Nine months ended September 30,
	2024		2023		2024		2023

	(in millions)				(in millions)
Non-cash commodity derivative gain (loss)	$	373	$	( 109 )	$	325	$	92


Settlements and premiums	( 17 )		( 95 )		( 35 )		( 223 )

Net gain (loss) from commodity derivatives	$	356	$	( 204 )	$	290	$	( 131 )

We report gains and losses on our derivative contracts for purchased natural gas used to generate steam for our steamflood operations as a component of operating expense on our consolidated statement of operations. For the three and nine months ended September 30, 2024, we recognized a net loss of $ 9 million (which includes a non-cash gain of $ 3 million and $ 12 million of settlement payments) and a net loss of $ 11 million (which includes a non-cash gain of $ 7 million and $ 18 million of settlement payments) in other operating expenses, net on our condensed consolidated statement of operations. We did not have derivative contracts related to purchased natural gas for our marketing activities during the three and nine months ended September 30, 2023.

Our derivative contracts are measured at fair value using industry-standard models with various inputs, including quoted forward prices, and are classified as Level 2 in the required fair value hierarchy for the periods presented.

The following tables present the fair values of our outstanding commodity derivatives as of September 30, 2024 and December 31, 2023. See Note 2 Aera Merger for the fair value of Aera's acquired derivative contracts on July 1, 2024.


September 30, 2024
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value

	(in millions)
Other current assets, net	$	59	$	( 13 )	$	46
Other noncurrent assets	34		( 12 )		22

Current liabilities	( 32 )		13		( 19 )
Noncurrent liabilities	( 67 )		12		( 55 )
	$	( 6 )	$	—	$	( 6 )


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 (benefit) and effective tax rate:


	Three months ended September 30,						Nine months ended September 30,
	2024			2023			2024			2023
	(in millions)						(in millions)
Income (loss) before income taxes	$	483		$	( 30 )		$	475		$	481

Current income tax provision	48			32			48			89
Deferred income tax provision (benefit)	90			( 40 )			84			16
Total income tax provision (benefit)	$	138		$	( 8 )		$	132		$	105

Effective tax rate	29		%	27		%	28		%	22		%

The difference between our annual effective tax rate as shown in the table above and the U.S. federal statutory tax rate of 21% is primarily due to state taxes where the state statutory tax rate is 7% (net of the federal tax deduction). Our annual effective rate of 22 % differed from the U.S. federal statutory rate of 21% for the nine months ended September 30, 2023 primarily due to state taxes and the recognition of a tax benefit for the release of a valuation allowance, which was recognized in 2022. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Income Taxes in our 2023 Annual Report for additional information on the release of the valuation allowance.

We had net deferred tax assets of $ 50 million and net deferred tax liabilities of $ 124 million as of September 30, 2024. As of December 31, 2023, we had a net deferred tax asset of $ 132 million. The change of $ 206 million primarily relates to the assumption of a deferred tax liability estimated at $ 120 million upon the acquisition of Aera on July 1, 2024. For further information on the acquisition of Aera, see Note 2 Aera Merger . The remaining increase in our deferred tax liability primarily relates to Aera’s unrealized gains on derivative contracts during the three months ended September 30, 2024 which are not recognized for tax purposes until settlement. Management expects to realize the deferred tax assets primarily through future income and reversal of taxable temporary differences. Realization of our existing deferred tax assets is not assured and depends on a number of factors including our ability to generate sufficient taxable income in future periods.

There are no ongoing examinations related to CRC or Aera. As the surviving entity after the Aera Merger, we are responsible for managing Aera's examinations, if any, for years that remain subject to examination. For Aera, years ending December 31, 2021 through December 31, 2023 remain subject to examination for U.S. federal tax purposes and years ending December 31, 2020 through December 31, 2023 remain subject to examination for California tax purposes.

NOTE 8 DIVESTITURES, ACQUISITIONS AND ASSETS HELD FOR SALE

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 purchase price of $ 10 million and recognized a $ 6 million gain.

Other

During the nine months ended September 30, 2024, we sold non-core assets recognizing a $ 1 million gain. During the nine months ended September 30, 2023, we sold a non-producing asset in exchange for the assumption of liabilities, recognizing a $ 7 million gain related to the liability reduction.

Acquisitions

In the nine months ended September 30, 2024, we acquired land for our carbon management business for approximately $ 6 million. In the nine months ended September 30, 2023, we acquired land for our carbon management business for approximately $ 1 million.

Assets Held for Sale

Ventura Basin Transactions

During 2021 and 2022, we entered into transactions to sell our Ventura basin assets. The transaction contemplates multiple closings that are subject to customary closing conditions. The transfer of the remaining assets in the Ventura basin was approved in June 2024 by the State Lands Commission. We completed the sale of these assets in October 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 September 30, 2024 and December 31, 2023. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Divestitures and Acquisitions in our 2023 Annual Report for additional information on the Ventura basin transactions. See Note 15 Subsequent Events for information on the closing of the sale that occurred in October 2024.

Other

In 2022, we acquired properties for carbon management activities for approximately $ 17 million, with the intent to divest a portion of these assets. We recorded these assets at fair value recognizing an impairment of $ 3 million in the first quarter of 2023. The fair value, using Level 3 inputs in the fair value hierarchy, declined during the first quarter of 2023 due to market conditions (including inflation and rising interest rates). The assets being divested are classified as held for sale as of September 30, 2024 on our condensed consolidated balance sheet.

NOTE 9 STOCKHOLDERS' EQUITY

The following table is a summary of common stock issuances:


						Common Stock

Balance at December 31, 2023						68,693,885
Issued as part of the Aera Merger						21,315,707
Shares repurchased						( 2,604,922 )
Shares issued for exercised warrants						1,139,163
Other shares issued, net						917,840
Balance at September 30, 2024						89,461,673

Share Repurchase Program

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $ 1.35 billion of our common stock through 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 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 September 30, 2023	365,145	$	20	$	54.75
Three months ended September 30, 2024	835,319	$	42	$	50.23

Nine months ended September 30, 2023	3,407,655	$	143	$	41.69
Nine months ended September 30, 2024	2,604,922	$	135	$	51.33

Inception of Program (May 2021) through September 30, 2024	17,468,837	$	739	$	42.14

Note: The total value of shares purchased includes approximately $ 1 million in both the nine months ended September 30, 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.

Dividends

On August 2, 2024, our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of $ 1.55 per share of common stock , payable to shareholders in quarterly increments of $ 0.3875 per share of common stock.

Our Board of Directors declared the following cash dividends for each of the periods presented.


	Total Dividend		Rate Per Share
	(in millions)		($ per share)
2024
Three months ended March 31, 2024	$	21	$	0.31
Three months ended June 30, 2024	22		$	0.31
Three months ended September 30, 2024	34		$	0.3875
Nine months ended September 30, 2024	$	77
2023
Three months ended March 31, 2023	$	20	$	0.2825
Three months ended June 30, 2023	20		$	0.2825
Three months ended September 30, 2023	19		$	0.2825
Nine months ended September 30, 2023	$	59

In addition to dividends on our common stock shown in the table above, we paid $ 4 million of dividend equivalents on equity-settled stock-based compensation awards in the nine months ended September 30, 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 15 Subsequent Events for information on future cash dividends.

Warrants

In October 2020, we reserved an aggregate 4,384,182 shares of our common stock for issuance upon the exercise of warrants, which were exercisable at $ 36 per share through October 28, 2024.

As of September 30, 2024, we had outstanding warrants exercisable into 2,812,754 shares of our common stock (subject to adjustments pursuant to the terms of the warrants). During the three and nine months ended September 30, 2024, we issued 1,085,838 and 1,139,163 shares of our common stock in exchange for warrants, respectively. During the three and nine months ended September 30, 2023, we issued 1,958 and 2,179 shares of our common stock in exchange for warrants, respectively.

See Note 15 Subsequent Events for warrant exercises during October 2024.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 10 Stockholders' Equity in our 2023 Annual Report for additional information on the terms of our warrants.

NOTE 10 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) were calculated using the treasury stock method for the three and nine months ended September 30, 2024 and 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 nine months ended September 30, 2024 and 2023:


	Three months ended September 30,				Nine months ended September 30,
	2024		2023		2024		2023

	(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS
Net income (loss)	$	345	$	( 22 )	$	343	$	376





Denominator for Basic EPS
Weighted-average shares	89.4		68.7		75.5		69.9

Potential common shares, if dilutive:
Warrants	1.0		—		1.1		0.8
Restricted stock units	0.4		—		0.5		1.0
Performance stock units	0.4		—		0.5		0.9

Denominator for Diluted EPS
Weighted-average shares	91.2		68.7		77.6		72.6

EPS
Basic	$	3.86	$	( 0.32 )	$	4.54	$	5.38
Diluted	$	3.78	$	( 0.32 )	$	4.42	$	5.18

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 September 30,		Nine months ended September 30,
	2024	2023	2024	2023

	(in millions)		(in millions)
Shares issuable upon exercise of warrants	—	4.3	—	—
Shares issuable upon settlement of RSUs	—	1.3	—	—
Shares issuable upon settlement of PSUs	—	1.6	—	—
Total antidilutive shares	—	7.2	—	—

NOTE 11 PENSION AND POSTRETIREMENT BENEFIT PLANS

Prior to the Aera Merger, we had two qualified defined benefit pension plans covering union employees and a postretirement health care plan for certain retired employees. In connection with the Aera Merger, we acquired two defined benefit pension plans, a qualified retirement plan and a supplemental retirement plan. We also acquired two plans that provide health care benefits for certain retired employees. Certain of the postretirement benefit obligations are funded through 401(h) accounts under the defined benefit plans. Aera's pension and postretirement obligations were remeasured as of the July 1, 2024 acquisition date. At that time, we recognized a net benefit asset of $ 73 million, included in other noncurrent assets, and a net benefit liability of $ 35 million, included in other long-term liabilities, on our condensed consolidated statement of financial position. Accumulated other comprehensive income balances were eliminated in purchase accounting.

In August 2024, we amended Aera's pension and postretirement benefit plans. For Aera’s defined benefit pension plans and post age 65 postretirement benefit plan, participants no longer earn benefits for service after September 30, 2024. However, future service will count towards vesting of benefits accumulated based on past service. For Aera’s postretirement benefit plans, we expanded the eligibility provisions in the event of an involuntary layoff. Following the Aera Merger, we recognized a curtailment gain of $ 4 million and a one-time cost of special termination benefits of $ 4 million included in net periodic benefit costs for the three and nine months ended September 30, 2024 as shown in the table below.

The following table sets forth the components of the net periodic benefit costs for our defined benefit pension and postretirement benefit plans for the three and nine months ended September 30, 2024 and 2023:



	Three months ended September 30,				Three months ended September 30,
	2024				2023
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit

	(in millions)				(in millions)
Service cost - benefits earned during the period	$	3	$	1	$	—	$	—
Interest cost on projected benefit obligation	4		1		—		—
Expected return on plan assets	( 6 )		( 1 )		—		—
Curtailment gain	—		( 4 )				( 3 )


Cost of special termination benefits	—		4		—		—
Amortization of prior service cost credit	—		( 1 )		—		( 1 )
Net periodic benefit costs	$	1	$	—	$	—	$	( 4 )


	Nine months ended September 30,				Nine months ended September 30,
	2024				2023
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit

	(in millions)				(in millions)
Service cost - benefits earned during the period	$	3	$	2	$	—	$	1
Interest cost on projected benefit obligation	4		2		1		2
Expected return on plan assets	( 7 )		( 1 )		( 1 )		—
Curtailment gain	—		( 4 )		—		( 3 )
Recognized actuarial gain	—		( 1 )		—		( 1 )
Cost of special termination benefits	—		4		—		—
Amortization of prior service cost credit	—		( 4 )		—		( 4 )
Net periodic benefit costs	$	—	$	( 2 )	$	—	$	( 5 )

We made no contributions to our defined benefit pension plans during the three months ended September 30, 2024 and contributed $ 2 million to our defined benefit plans during the nine months ended September 30, 2024. We made no contributions during the three and nine months ended September 30, 2023. We do not expect to make any significant contributions to our defined benefit pension plans during the remainder of 2024.

NOTE 12 SUPPLEMENTAL ACCOUNT BALANCES

Restricted cash — Restricted cash of $ 28 million at September 30, 2024 primarily includes funds held in an escrow account established to secure oil field well and infrastructure abandonment and habitat restoration at an oil and gas field previously owned by Aera. Funds will be released from the escrow account as work is completed. The Merger Agreement provides that 50 % of the amount by which released funds exceeds the cumulative abandonment and restoration expenditures from January 1, 2024 onward is payable to the Sellers. We do not expect this amount to be significant. Restricted cash included an insignificant amount that was restricted under oil and natural gas liens in favor of one of our suppliers. We had no restricted cash at December 31, 2023.

Revenues — We derive most of our revenue from sales of oil, natural gas and NGLs, with the remaining revenue primarily generated from sales of electricity and marketing activities related to storage and managing excess pipeline capacity. The following table provides disaggregated revenue for sales of produced oil, natural gas and NGLs to customers:



	Three months ended September 30,				Nine months ended September 30,
	2024		2023		2024		2023

	(in millions)				(in millions)
Oil	$	804	$	402	$	1,505	$	1,154
Natural gas	22		61		68		367
NGLs	44		47		138		151
Oil, natural gas and NGL sales	$	870	$	510	$	1,711	$	1,672

Since July 1, 2024, the closing date of the Aera Merger, the results of operations for Aera have been included in our consolidated financial statements. For the period from July 1, 2024 to September 30, 2024, $ 475 million of oil, natural gas and NGL sales attributable to Aera's business has been included in the consolidated statements of operations.

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 statements 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 marketing oil sales that have resulted from third-party purchases. The following table provides disaggregated revenue for sales to customers related to our marketing activities:



	Three months ended September 30,				Nine months ended September 30,
	2024		2023		2024		2023

	(in millions)				(in millions)
Oil	$	25	$	—	$	73	$	—
Natural gas	26		78		97		334
NGLs	—		( 1 )		6		2
Revenue from marketing of purchased commodities	$	51	$	77	$	176	$	336

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



	September 30,		December 31,
	2024		2023

	(in millions)
Materials and supplies	$	71	$	68
Finished goods	4		4
Inventories	$	75	$	72

In the nine months ended September 30, 2024, we recorded an impairment of excess and obsolete materials and supplies of $ 13 million. The impairment related to the write-down of obsolete materials and supplies to fair value using Level 3 inputs in the fair value hierarchy.

We also acquired inventory with an estimated value of $ 18 million in connection with the Aera Merger. See Note 2 Aera Merger for additional information.

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


	September 30,		December 31,
	2024		2023

	(in millions)
Net amounts due from joint interest partners (a)	$	34	$	43

Fair value of commodity derivative contracts	46		21
Prepaid expenses	18		19
Greenhouse gas allowances	49		12



Other	37		18
Other current assets, net	$	184	$	113

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

Other noncurrent assets — Other noncurrent assets include the following:



	September 30,		December 31,
	2024		2023

	(in millions)
Operating lease right-of-use assets	$	100	$	73
Deferred financing costs - Revolving Credit Facility	17		11
Emission reduction credits	21		11
Prepaid power plant maintenance	3		34
Fair value of commodity derivative contracts	22		6
Funded pension	89		2
Deposits and other	34		11
Other noncurrent assets	$	286	$	148

Accrued liabilities — Accrued liabilities include the following:


	September 30,		December 31,
	2024		2023

	(in millions)
Employee-related costs	$	165	$	82
Taxes other than on income	97		35
Asset retirement obligations	130		99
Interest	29		18
Operating lease liability	20		15
Fair value of derivative contracts	19		8
Premiums due on commodity derivative contracts	13		21
Liability for settlement payments on commodity derivative contracts	1		8
Amounts due under production-sharing contracts	4		5
Signal Hill maintenance	1		12
Income taxes payable	11		18

Other	51		45
Accrued liabilities	$	541	$	366

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



	September 30,		December 31,
	2024		2023

	(in millions)
Compensation-related liabilities	$	48	$	38
Postretirement and pension benefit plans	68		36
Operating lease liability	71		55

Premiums due on commodity derivative contracts	5		10
Contingent liability (related to Carbon TerraVault JV put and call rights)	104		52
Other	41		8
Other long-term liabilities	$	337	$	199

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 with the Carbon TerraVault JV. See Note 3 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV. Since July 1, 2024, the closing date of the Aera Merger, the results of operations for Aera have been included in our consolidated financial statements. The amounts shown for our exploration and production business includes $ 46 million related to Aera during the period of July 1, 2024 through September 30, 2024.


	Three months ended September 30,				Nine months ended September 30,
	2024		2023		2024		2023

	(in millions)				(in millions)
Exploration and production, corporate and other	$	104	$	61	$	219	$	191
Carbon management business	2		4		7		10
Total general and administrative expenses	$	106	$	65	$	226	$	201

NOTE 13 SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental disclosures to our condensed consolidated statements of cash flows are presented below:


	Three months ended September 30,				Nine months ended September 30,
	2024		2023		2024		2023

	(in millions)				(in millions)
Supplemental Cash Flow Information
Interest paid, net of amount capitalized	$	23	$	22	$	42	$	44
Income taxes paid	$	29	$	29	$	55	$	80
Interest income	$	1	$	5	$	15	$	14

Supplemental Disclosure of Non-cash Investing and Financing Activities
Contribution to the Carbon TerraVault JV	$	15	$	4	$	20	$	7
Issuance of shares for stock-based compensation awards	$	—	$	2	$	88	$	3
Dividends accrued for stock-based compensation awards	$	2	$	1	$	2	$	2
Excise tax on share repurchases	$	—	$	—	$	1	$	1

NOTE 14 CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have designated certain of our subsidiaries as Unrestricted Subsidiaries under the indenture governing our 2026 Senior Notes (2026 Senior Notes Indenture) and 2029 Senior Notes (2029 Senior Notes Indenture). Unrestricted Subsidiaries (as defined in the 2026 Senior Notes Indenture and 2029 Senior Notes Indenture) are subject to fewer restrictions under the indentures. We are required under the 2026 Senior Notes Indenture and 2029 Senior Notes Indenture to present the financial condition and results of operations of CRC and its Restricted Subsidiaries (as defined in the 2026 Senior Notes Indenture and 2029 Senior Notes Indenture) separate from the financial condition and results of operations of its Unrestricted Subsidiaries. The following condensed consolidating balance sheets as of September 30, 2024 and December 31, 2023 and the condensed consolidating statements of operations for the three and nine months ended September 30, 2024 and 2023, as applicable, reflect the condensed consolidating financial information of CRC (Parent), our combined Unrestricted Subsidiaries, our combined Restricted Subsidiaries and the elimination entries necessary to arrive at the information for the Company on a consolidated basis. The financial information may not necessarily be indicative of the financial condition and results of operations had the Unrestricted Subsidiaries operated as independent entities.

Condensed Consolidating Balance Sheets

As of September 30, 2024 and December 31, 2023


	As of September 30, 2024
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total current assets	$	251	$	46	$	575	$	—	$	872
Total property, plant and equipment, net	12		24		5,800		—		5,836
Investments in consolidated subsidiaries	5,031		( 27 )		14,638		( 19,642 )		—
Deferred tax asset	50		—		—		—		50
Investment in unconsolidated subsidiaries	—		29		55		—		84
Other assets	19		51		216		—		286
TOTAL ASSETS	$	5,363	$	123	$	21,284	$	( 19,642 )	$	7,128

Total current liabilities	125		15		757		—		897
Long-term debt	1,131		—		—		—		1,131
Asset retirement obligations	—		—		1,083		—		1,083
Other long-term liabilities	72		130		190		—		392
Deferred tax liability	124		—		—		—		124
Amounts due to (from) affiliates	410		19		( 429 )		—		—
Total equity	3,501		( 41 )		19,683		( 19,642 )		3,501
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	5,363	$	123	$	21,284	$	( 19,642 )	$	7,128


	As of December 31, 2023
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total current assets	$	511	$	20	$	398	$	—	$	929
Total property, plant and equipment, net	14		12		2,744		—		2,770
Investments in consolidated subsidiaries	2,311		( 11 )		1,347		( 3,647 )		—
Deferred tax asset	132		—		—		—		132
Investment in unconsolidated subsidiary	—		19		—		—		19
Other assets	12		36		100		—		148
TOTAL ASSETS	$	2,980	$	76	$	4,589	$	( 3,647 )	$	3,998

Total current liabilities	142		13		461		—		616
Long-term debt	540		—		—		—		540
Asset retirement obligations	—		—		422		—		422
Other long-term liabilities	79		73		49		—		201

Total equity	2,219		( 10 )		3,657		( 3,647 )		2,219
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	2,980	$	76	$	4,589	$	( 3,647 )	$	3,998

Condensed Consolidating Statement of Operations

For the three and nine months ended September 30, 2024 and 2023


	Three months ended September 30, 2024
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total operating revenues	$	2	$	—	$	1,437	$	( 86 )	$	1,353
Total costs and other	86		16		818		( 85 )		835

Non-operating (loss) income	( 32 )		( 5 )		2		—		( 35 )
(LOSS) INCOME BEFORE INCOME TAXES	( 116 )		( 21 )		621		( 1 )		483
Income tax provision	( 138 )		—		—		—		( 138 )
NET (LOSS) INCOME	$	( 254 )	$	( 21 )	$	621	$	( 1 )	$	345


	Three months ended September 30, 2023
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total operating revenues	$	6	$	—	$	454	$	—	$	460
Total costs and other	66		12		397		—		475

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


	Nine months ended September 30, 2024
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total operating revenues	$	15	$	—	$	2,407	$	( 101 )	$	2,321
Total costs and other	222		44		1,611		( 101 )		1,776
Gain on asset divestitures	—		—		7		—		7
Non-operating (loss) income	( 66 )		( 16 )		5		—		( 77 )
(LOSS) INCOME BEFORE INCOME TAXES	( 273 )		( 60 )		808		—		475
Income tax provision	( 132 )		—		—		—		( 132 )
NET (LOSS) INCOME	$	( 405 )	$	( 60 )	$	808	$	—	$	343


	Nine months ended September 30, 2023
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total operating revenues	$	14	$	—	$	2,061	$	—	$	2,075
Total costs and other	177		31		1,349		—		1,557
Gain on asset divestitures	—		—		7		—		7
Non-operating (loss) income	( 39 )		( 9 )		4		—		( 44 )
(LOSS) INCOME BEFORE INCOME TAXES	( 202 )		( 40 )		723		—		481
Income tax provision	( 105 )		—		—		—		( 105 )
NET (LOSS) INCOME	$	( 307 )	$	( 40 )	$	723	$	—	$	376

NOTE 15 SUBSEQUENT EVENTS

Amendment to our Revolving Credit Facility

On November 1, 2024, we amended our existing Revolving Credit Facility. The amendments included, among other things:

• increasing the amount of the revolving commitments by $ 50 million to $ 1,150 million to reflect changes to our lender group;

• extending the maturity date of the facility from July 31, 2027 to March 16, 2029;

• amending the springing maturity to permit our 2026 Senior Notes to remain outstanding past October 31, 2025 so long as the aggregate availability (less the outstanding 2026 Senior Notes) is not less than 25 % of the total revolving commitments;

• increasing our capacity to issue letters of credit from $ 250 million to $ 300 million; and

• other technical amendments.

Borrowing Base Redetermination

The borrowing base under our Revolving Credit Facility is redetermined semi-annually and was reaffirmed at $ 1.5 billion on November 1, 2024.

Dividend

On November 5, 2024 , our Board of Directors declared a quarterly cash dividend of $ 0.3875 per share of common stock. The dividend is payable to shareholders of record at the close of business on December 2, 2024 and is expected to be paid on December 16, 2024 .

Ventura Basin Divestiture

On October 14, 2024, we completed the sale of Ventura basin assets for net proceeds of $ 3 million. See Note 8 Divestitures, Acquisitions and Assets Held for Sale above and Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Divestitures and Acquisitions in our 2023 Annual Report for additional information on the Ventura basin transactions.

Warrants

During October 2024, we issued 2,630,540 shares of our common stock in connection with warrant exercises. Since the issuance date of the warrants in October 2020, 3,856,833 shares have been issued upon the exercise of warrants and 469,429 shares were cancelled due to net settlement. On October 28, 2024, any unexercised warrants expired in accordance with their terms and 57,920 shares underlying such warrants were never issued.

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

General

Aera Merger

On July 1, 2024, we closed on transactions pursuant to the definitive agreement and plan of merger (Merger Agreement) to obtain all of the ownership interests in Aera Energy, LLC (Aera) (Aera Merger). In connection with the closing of the Aera Merger, we issued 21,315,707 shares of common stock to the former Aera owners (Sellers). We also paid approximately $990 million in connection with the extinguishment of all of Aera's outstanding indebtedness using the proceeds from the issuance of our 2029 Senior Notes and cash on hand. For more information on the 2029 Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 4 Debt.

As of July 1, 2024, immediately following closing of the Aera Merger, our existing stockholders prior to the Aera Merger owned 76% of CRC and the Sellers owned 24% of CRC.

In the three and nine months ended September 30, 2024, we recognized $30 million and $56 million, respectively, of transaction and integration costs related to the Aera Merger which are included in other operating expenses, net on our condensed consolidated statement of operations. See Part I, Item 1 – Financial Statements, Note 4 Debt for information on financing costs related to the Aera Merger.

Reorganization

In August 2024, management committed to a reduction in force as part of the integration process following the Aera Merger, which, when complete, will result in a 12% reduction in our combined company's employee headcount. We initiated this workforce reduction to align the size and composition of our workforce with expected future operating and capital plans and to capture synergies related to the Aera Merger. As a result, we recognized a charge of $27 million and $28 million in other operating expenses, net on the consolidated statement of operations for the three and nine months ended September 30, 2024, respectively, primarily related to severance benefits. See Part I, Item 1 – Financial Statements, Note 11 Pension and Postretirement Benefit Plans for information on amendments to Aera’s pension and postretirement benefit plans in August 2024.

We expect to pay severance costs of approximately $25 million in the fourth quarter of 2024 and the remaining amounts throughout 2025 as the workforce reduction will be achieved in stages due to transition periods. See Part I, Item 1 – Financial Statements, Note 2 Aera Merger for information on the severance plan and Note 11 Pension and Postretirement Benefit Plans for information on amendments to Aera's pension and postretirement benefit plans.

Recent Debt Transactions

2029 Senior Notes Follow-On Offering

On August 22, 2024, we completed a follow-on offering of $300 million in aggregate principal amount of 8.25% senior notes due 2029 (2029 Senior Notes). The net proceeds from this offering of $298 million, after $3 million of debt premium and $5 million of debt issuance costs, were used to repurchase a portion of our outstanding 7.125% senior notes due 2026 (2026 Senior Notes) as described below. The 2029 Senior Notes issued on August 22, 2024 are governed by the same indenture as the $600 million of 2029 Senior Notes that were previously issued on June 5, 2024.

2026 Senior Note Repurchases

In the three and nine months ended September 30, 2024, we repurchased $300 million in face value of our 2026 Senior Notes for $303 million, resulting in a loss on early extinguishment of debt in the amount of $5 million which includes a $2 million write-off of unamortized debt issuance costs. In the three and nine months ended September 30, 2023, we repurchased $5 million in face value of our 2026 Senior Notes at par resulting in an insignificant extinguishment loss for the write-off of unamortized debt issuance costs.

Fifth Amendment to Revolving Credit Facility

On November 1, 2024, we entered into a fifth amendment to our Revolving Credit Facility. For more information on recent amendments to our Revolving Credit Facility, see Part I, Item 1 – Financial Statements, Note 4 Debt and Note 15 Subsequent Events.

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. Refer to Prices and Realizations below for information on our realized prices.

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


	Three months ended				Nine months ended
	September 30, 2024		June 30, 2024		September 30, 2024		September 30, 2023
Brent oil ($/Bbl)	$	78.54	$	85.00	$	81.79	$	82.06
WTI oil ($/Bbl)	$	75.09	$	80.57	$	77.54	$	77.39
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	$	2.16	$	1.89	$	2.10	$	2.69

Marketing Arrangements

Crude Oil

We sell nearly all of our crude oil to California refiners. A majority of our crude oil production is connected to third-party pipelines and California refining markets via our gathering systems. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.

The prices paid by California refiners are typically based on local postings that are closely tied to Brent prices. International waterborne-based Brent prices are relevant because there is limited crude pipeline infrastructure available to transport crude over land from other parts of the United States into California. We believe that these limitations will continue to contribute to higher realized prices in California than most other U.S. oil markets for comparable grades.

In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025. For the three months ended September 30, 2024, following the Aera Merger, we sold approximately 8% of our production to this refinery. Following the closure of this facility, there will be four remaining major (greater than 75,000 barrels per day) petroleum refineries in Southern California and three remaining major petroleum refineries in Northern California. Due to the significant excess of refining capacity in California versus the quantity of crude oil produced locally, we do not expect the closure of this refinery to affect our ability to market our crude oil production, or to negatively impact our price realizations.

Natural Gas

We sell all of our natural gas not used in our operations into the California market. A majority of these sales are made at index-based prices. Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity between the market and producing areas. Transportation capacity influences prices because California imports more than 90% of its natural gas from other states and from Canada. As a result, we typically obtain higher realizations relative to out-of-state producers due to lower transportation costs on the delivery of our natural gas.

In addition to selling natural gas, we also purchase natural gas for production of steam at our steamfloods and for power generation. As a result, the positive impact of higher natural gas prices is, absent impacts of gas cost hedging, largely offset by higher operating costs of our steamfloods and in our electricity generation expense, but higher prices have a net positive effect on our operating results when gas hedges are taken into account. See Part I, Item 1 – Financial Statements, Note 6 Derivatives for more information on derivative contracts related to purchased natural gas .

Following the Aera Merger, we have transportation contracts for up to (i) 101,750 MMBtu/d of long-haul (Rockies to California) gas transportation through September 2031 and (ii) approximately 220,000 MMBtu/d of localized system natural gas transportation through September 2026. These contracts to transport natural gas contain both fixed reservation fees and variable charges.

NGLs

NGL prices vary by liquid type and realizations are closely correlated to the different commodity prices to which they relate. Prices can also fluctuate due to the demand for certain chemical products (for which NGLs are used as feedstock) and due to infrastructure constraints and seasonality. Finally, our results are also affected by the performance of our natural gas-processing plants. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the remaining products as NGLs. The efficiency with which we extract liquids from the wet gas stream affects our production volumes and operating results. Our natural gas-processing plants also facilitate access to third-party delivery points near the Elk Hills field.

We currently have a ship-or-pay pipeline transportation contract for approximately 6,100 barrels per day of NGLs through March 2026. Our contract to transport NGLs requires us to cash settle any shortfall between the contractual throughput minimums and volumes actually shipped. We have met all our throughput minimums under this contract for the periods presented.

Delivery Commitments

We have commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs, including additional delivery commitments obtained as part of the Aera Merger. As of September 30, 2024, we had the following delivery commitments as shown in the table below.


	2024	2025	2026	2027	2028
Oil (MMBbl)	12	34	28	21	3
NGL (MMBbl)	1	1	—	—	—
Natural gas (Bcf)	11	4	—	—	—

We expect to fulfill our delivery commitments predominantly from our production and to a lesser extent from third party volumes acquired in connection with our marketing activities. We typically enter into index-based contracts with prices set at the time of delivery.

Regulatory Updates

Well Permitting Status

CalGEM remains in the process of developing standard operating procedures for reviewing well permit applications and significant permitting delays may continue pending CalGEM’s completion of this process. An increase in approvals for workovers has continued through the third quarter of 2024. As of September 30, 2024, we have received 581 permits for workovers and 89 permits for sidetracks (including permits received by Aera) since the beginning of the year.

During the second and third quarters of 2024, CalGEM issued 48 and 34 new well permits to other operators in the state, respectively. These permits were issued outside of Kern County or in reliance on an environmental impact analysis other than the Kern County Environmental Impact Report (EIR) to comply with CEQA. We are pursuing a similar strategy of seeking conditional use permits with respect to our Elk Hills, Buena Vista and Kern Front fields and Aera's Belridge field that would allow us to comply with CEQA requirements separate from the Kern County EIR. As discussed in the 2023 Annual Report, the Kern County EIR was legally challenged in 2020 and the use of the Kern County EIR is currently stayed and has been stayed through most of the litigation. For further information on the Kern County EIR, see Part I, Item IA – Risk Factors, We may face material delays related to our ability to timely obtain permits necessary for our operations or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments in our 2023 Annual Report. As a result, our ability to obtain these conditional use permits is uncertain and we may not be successful in obtaining such permits in a timely manner or at all.

CCS Project Permitting Status

On October 21, 2024, the Kern County Board of Supervisors approved the issuance of the conditional use permits and certified the Draft Recirculated Environmental Impact Report for our first carbon capture and storage project, Carbon TerraVault I. This approval follows a recommendation from the Kern County Planning Commission (Planning Commission) on September 12, 2024 that the Kern County Board of Supervisors take these actions.

Setbacks and Senate Bill No. 1137

California Senate Bill No. 1137 establishes 3,200 feet as the minimum distance between new oil and natural gas production wells and certain sensitive receptors such as homes, schools and businesses open to the public and separately imposes a number of potential impact analysis and mitigation and reporting requirements. The implementation of Senate Bill No. 1137 was stayed pending the outcome of a voter referendum to repeal the bill on the November 2024 ballot, but the referendum was withdrawn on June 27, 2024. However, on September 30, 2024, the Governor signed into law Assembly Bill No. 218, which extends the timeline for the implementation of certain initial and future monitoring and reporting requirements to July 1, 2026 and further delays compliance with certain other requirements of Senate Bill No. 1137 by up to three years. Assembly Bill. No. 218 does not modify the 3,200-foot setback requirements applicable to new drills, sidetracks or workovers.

The majority of our production is in rural areas in the San Joaquin basin and is not affected by Senate Bill No. 1137. In addition to the writedown of reserves previously recorded in 2023, we continue to evaluate the location of projects near setback zones and believe any further reductions to the net present value of our proved undeveloped reserves as a result of the withdrawal of the voter referendum and the implementation of Senate Bill No. 1137 would be less than $14 million based on 2023 SEC prices (with an insignificant impact on our overall proved reserves).

Recent Legislation

On September 25, 2024, the following laws were enacted in the State of California:

Assembly Bill 1866

This law increases the annual fees operators must pay per idle well, depending on how long each well has been idle, and includes a new fee for those wells that have been idle for less than three years. In lieu of the annual fees, operators can instead file an eight year plan with the state to provide for the management and elimination of its idle wells. This law also increases the minimum percentages of idle wells that operators are required to eliminate each year. The rate at which idle wells must be eliminated varies depending on the number of an operator’s idle wells. Operators must prepare and submit a plan for the elimination of idle wells to CalGEM for approval. We have robust programs for managing and eliminating idle wells that in most cases meet or exceed the requirements of the new law. As a result, we do not expect this new law to have any meaningful impact on our current plans for eliminating idle wells or meaningfully increase fees associated with our idle wells.

Assembly Bill 2716

This law requires operators to plug “low production wells” located within the boundary of the Baldwin Hills Conservancy in Los Angeles within a certain timeframe or otherwise subjects operators to administrative penalties. A “low-production well” is a well that produced fewer than 15 barrels of oil a day during the past 12 months. We have limited operations and assets within the affected area. As a result, we expect that this law will have an insignificant impact on both our total production and proved reserves.

Assembly Bill 3233 (AB 3233)

This law provides local governments with the authority to limit methods for, or even prohibit oil and gas operations or development within their jurisdiction, including with respect to existing operations. Prior to the passage of this law, certain local governments in California had attempted to limit oil and gas operations within their jurisdictions and such actions had been challenged and struck down by California courts. Monterey County previously sought to ban only new production and prohibit the use of wastewater injection as a production method. The City and County of Los Angeles previously sought to both ban new wells and phaseout existing wells over a certain period of time. Although both those local measures were struck down in court, following the adoption of AB 3233, certain legal challenges previously made to these local actions are no longer valid and it is possible that these or other local governments in California may attempt to pass new or similar restrictions. For the three months ended September 30, 2024, approximately 12% of our gross production is located in Los Angeles County and approximately 3% is in Monterey County.

For the three months ended September 30, 2024, over 80% of our gross production is located in Kern County, and at this time we are not aware of any local governments within Kern County that are considering materially limiting or otherwise prohibiting oil and gas operations within their jurisdiction. However, it is difficult to predict how local governments in California may choose to exercise their new authority under AB 3233. There may be future legal challenges to AB 3233 and any local ordinances enacted thereunder and we cannot predict whether or not such challenges will be successful.

See Part II, Item 1A – Risk Factors – We may face increased local restrictions on oil and gas exploration and production operations or even be prohibited from operating in certain areas as a result of recently enacted California legislation .

Results of Oil and Gas Operations

The tables below present production information on the basis of gross production, net production and net production sold. The difference between gross production and net production primarily reflects the reduction for (i) volumes attributable to working interest and royalty owners and (ii) volumes associated with PSC-type contracts to arrive at our net share. The difference between net production and net production sold reflects (i) the reduction for natural gas that we produce that is used in our oil and gas operations, including steam in our steamflood operations, and (ii) marketing activities reflecting the storage of volumes that we produce and are sold at a later time.

The amounts in the production tables below include volumes produced from Aera's operated and non-operated fields during the period from July 1, 2024 through September 30, 2024 and volumes from CRC's operated and non-operated fields for each of the periods presented.

Net Production Sold

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


	Three months ended		Nine months ended
	September 30, 2024	June 30, 2024	September 30, 2024	September 30, 2023
Oil (MBbl/d)
San Joaquin Basin	90	30	50	34
Los Angeles Basin	17	17	17	19
Ventura Basin	6	—	2	—

Total	113	47	69	53
NGLs (MBbl/d)
San Joaquin Basin	10	10	11	11

Ventura Basin	1	—	—	—

Total	11	10	11	11
Natural gas (MMcf/d)
San Joaquin Basin	111	99	99	120
Los Angeles Basin	1	1	1	1
Ventura Basin	1	—	—	—
Sacramento Basin	13	14	14	15
Total	126	114	114	136

Total Net Production Sold (MBoe/d)	145	76	99	87

Total daily net production sold increased by 69 Mboe/d from 76 Mboe/d for the three months ended June 30, 2024 to 145 Mboe/d during the three months ended September 30, 2024 primarily as a result of the Aera Merger. Our natural gas production also increased during the three months ended September 30, 2024 as compared to the three months ended June 30, 2024 by 2 MBoe/d as a result of fewer days of downtime at our Elk Hills power plant. Our PSCs, which are described below, positively impacted our net oil production by 1 MBoe/d in the three months ended September 30, 2024 compared to the three months ended June 30, 2024.

Total daily net production sold increased by 12 Mboe/d from 87 MBoe/d during the nine months ended September 30, 2023 to 99 Mboe/d during the nine months ended September 30, 2024 primarily as a result of the Aera Merger. This increase was partially offset by lower production during the nine months ended September 30, 2024 compared to the prior year period due to natural decline, additional days of scheduled maintenance and unplanned downtime at our Elk Hills power plant and the divestiture of our share of a non-operated field in December 2023. Our PSCs, which are described below, negatively impacted our net oil production by 1 MBoe/d in the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023.

Net Produced

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


	Three months ended		Nine months ended
	September 30, 2024	June 30, 2024	September 30, 2024	September 30, 2023
Oil (MBbl/d)
San Joaquin Basin	90	30	51	34
Los Angeles Basin	17	16	17	19
Ventura Basin	6	—	2	—

Total	113	46	70	53
NGLs (MBbl/d)
San Joaquin Basin	11	11	10	11



Total	11	11	10	11
Natural gas (MMcf/d)
San Joaquin Basin	130	118	123	127
Los Angeles Basin	1	1	1	1
Ventura Basin	3	—	1	—
Sacramento Basin	13	14	14	16
Total	147	133	139	144

Total Net Produced (MBoe/d)	149	79	103	88

The following table reconciles our average net production sold and volumes produced 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		Nine months ended
	September 30, 2024	June 30, 2024	September 30, 2024	September 30, 2023

	(MBoe/d)
Total Net Production Sold	145	76	99	87
Changes in NGL inventory and other	4	3	4	1
Total Net Produced	149	79	103	88
Partners' share under PSCs	6	7	7	6
Working interest and royalty holders' share	10	7	8	8
Total Gross Production	165	93	118	102

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 that are in effect through the economic life of the assets. The reporting of our PSCs 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 PSCs, is a non-GAAP measure which adjusts for excess costs attributable to PSCs for the periods presented in the tables below:


	Three months ended
	September 30, 2024				June 30, 2024

	(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs (a)	$	316	$	23.73	$	159	$	23.14
Excess costs attributable to PSCs	(16)		(1.23)		(17)		(2.48)
Operating costs, excluding effects of PSCs	$	300	$	22.50	$	142	$	20.66

(a) Operating costs related to our exploration and production activities and are presented before elimination entries.


	Nine months ended
	September 30, 2024				September 30, 2023

	(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs (a)	$	654	$	24.11	$	636	$	26.80
Excess costs attributable to PSCs	(51)		(1.88)		(54)		(2.26)
Operating costs, excluding effects of PSCs	$	603	$	22.23	$	582	$	24.54

(a) 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 2023 Annual Report.

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 oil and natural gas operations for the periods presented:


	Three months ended
	September 30, 2024			June 30, 2024
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	78.54		$	85.00

Realized price without derivative settlements	$	77.10	98%	$	83.14	98%
Derivative settlements	(1.72)			(1.85)
Realized price with derivative settlements	$	75.38	96%	$	81.29	96%

WTI	$	75.09		$	80.57

Realized price without derivative settlements	$	77.10	103%	$	83.14	103%
Realized price with derivative settlements	$	75.38	100%	$	81.29	101%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	45.77	58%	$	46.96	55%
Realized price (% of WTI)	$	45.77	61%	$	46.96	58%

Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	2.16		$	1.89

Realized price ($/Mcf)	$	2.68	124%	$	1.78	94%


	Nine months ended
	September 30, 2024			September 30, 2023
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	81.79		$	82.06

Realized price without derivative settlements	$	79.15	97%	$	79.90	97%
Derivative settlements	(2.05)			(15.65)
Realized price with derivative settlements	$	77.10	94%	$	64.25	78%

WTI	$	77.54		$	77.39

Realized price without derivative settlements	$	79.15	102%	$	79.90	103%
Realized price with derivative settlements	$	77.10	99%	$	64.25	83%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	47.77	58%	$	48.89	60%
Realized price (% of WTI)	$	47.77	62%	$	48.89	63%

Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	2.10		$	2.69



Realized price ($/Mcf)	$	2.76	131%	$	9.85	366%

Oil — Brent prices were lower for the three months ended September 30, 2024 compared to the three months ended June 30, 2024. The decrease in Brent prices is attributable to stagnating demand growth and increased production from non-OPEC+ sources. Brent prices were largely unchanged for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 as markets attempted to reconcile continued geopolitical conflict, OPEC+ compliance and discipline, and slowing growth in global demand.

NGLs — NGL prices for the three months ended September 30, 2024 decreased compared to the three months ended June 30, 2024 reflecting traditional seasonality and moved in tandem with crude oil prices. NGL prices for the nine months ended September 30, 2024 decreased compared to the nine months ended September 30, 2023 as growing North American crude and associated gas production continue to provide an ample supply of wet gas for processing.

Natural Gas — Natural gas prices increased for the three months ended September 30, 2024 compared to the three months ended June 30, 2024 driven by a greater degree of producer discipline. Natural gas prices decreased for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023. In California, specifically, nine-month metrics continue to reflect record-setting prices in early 2023 versus near-record levels of gas in storage across the same period in 2024.

Statements of Operations Analysis

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 September 30, 2024 and June 30, 2024 and the nine months ended September 30, 2024 and 2023. Energy operating costs consist of purchased natural gas used to generate electricity for our operations and steam for our steamfloods, purchased electricity and internal costs to generate electricity used in our operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.


	Three months ended				Nine months ended
	September 30, 2024		June 30, 2024		September 30, 2024		September 30, 2023

	($ per Boe, except as otherwise stated)
Total net production sold (MBoe/d)	145		76		99		87
Total oil, natural gas and NGL sales (in millions)	$	878	$	416	$	1,729	$	1,672
Energy operating costs	$	7.29	$	6.40	$	7.26	$	10.87
Gas processing costs	0.38		0.44		0.44		0.59
Non-energy operating costs	16.06		16.30		16.41		15.34
Operating costs	$	23.73	$	23.14	$	24.11	$	26.80
Field general and administrative expenses (a)	$	4.06	$	1.31	$	2.65	$	1.39
Field depreciation, depletion and amortization (b)	$	10.21	$	6.84	$	8.55	$	6.62
Field taxes other than on income	$	5.41	$	4.80	$	5.05	$	3.92

(a) Excludes unallocated general and administrative expenses.

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

Consolidated Results of Operations

Our consolidated results of operations include the results of Aera beginning July 1, 2024, the closing date of the Aera Merger. For more information on the Aera Merger, see Part I, Item 1 – Financial Statements, Note 2 Aera Merger.

For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the 2026 Senior Notes Indenture and 2029 Senior Notes Indenture, see Part I, Item 1 – Financial Statements, Note 14 Condensed Consolidated Financial Information.

Certain prior period balances related to NGL marketing activities have been reclassified to conform to our 2024 presentation. For the nine months ended September 30, 2023, we reclassified $2 million related to NGL storage activities from other revenue to revenue from marketing of purchased commodities on our condensed consolidated statement of operations.

Three months ended September 30, 2024 compared to June 30, 2024

The following table presents our consolidated operating revenues for the three months ended September 30, 2024 and June 30, 2024:


	Three months ended
	September 30, 2024		June 30, 2024

	(in millions)
Oil, natural gas and NGL sales	$	870	$	412
Net gain from commodity derivatives	356		5
Revenue from marketing of purchased commodities	51		51
Electricity sales	69		36
Other revenue	7		10
Total operating revenues	$	1,353	$	514

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $870 million for the three months ended September 30, 2024, which is an increase of $458 million compared to $412 million for the three months ended June 30, 2024. This increase includes $475 million of oil, natural gas and NGL sales related to additional production from the Aera fields following the completion of the Aera Merger on July 1, 2024. The effect of cash settlements on our commodity derivative contracts are excluded from the table below. The table below includes sales of natural gas we produce which is used by our Elk Hills power plant.


	Oil		NGLs		Natural Gas		Total Operations

	(in millions)
Three months ended June 30, 2024	$	353	$	45	$	18	$	416
Change in realized prices	(26)		(1)		9		(18)
Change in production	477		—		3		480

Three months ended September 30, 2024	$	804	$	44	$	30	$	878

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

Net gain from commodity derivatives — Net gain from commodity derivatives was $356 million for the three months ended September 30, 2024 compared to net gain of $5 million for the three months ended June 30, 2024 as shown in the table below. As of July 1, 2024, we recorded a liability of $336 million for Aera's outstanding Brent-based derivative contracts. Due to a decline in forward oil prices between July 1, 2024 and September 30, 2024, we recognized a non-cash commodity derivative gain for these Aera hedges during the three months ended September 30, 2024. The net gain from commodity derivatives primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each measurement period.


	Three months ended
	September 30, 2024		June 30, 2024

	(in millions)
Non-cash commodity derivative gain	$	373	$	11


Settlements and premiums	(17)		(6)

Net gain from commodity derivatives	$	356	$	5

Electricity sales — Electricity sales increased by $33 million to $69 million for the three months ended September 30, 2024 compared to $36 million for the three months ended June 30, 2024. The increase was primarily a result of higher resource adequacy revenue and sales from electricity delivered to the wholesale market during the three months ended September 30, 2024.

The following table presents our consolidated operating and non-operating expenses and income for the three months ended September 30, 2024 and June 30, 2024:


	Three months ended
	September 30, 2024		June 30, 2024

	(in millions)
Operating expenses
Energy operating costs	$	92	$	41
Gas processing costs	5		3
Non-energy operating costs	214		112
General and administrative expenses	106		63
Depreciation, depletion and amortization	140		53
Asset impairment	—		13
Taxes other than on income	85		39
Exploration expense	1		—
Costs related to marketing of purchased commodities	43		43
Electricity generation expenses	9		14
Transportation costs	23		17
Accretion expense	31		13
Carbon management business expenses	13		15
Other operating expenses, net	73		51
Total operating expenses	835		477
Gain on asset divestitures	—		1
Operating income	518		38

Non-operating (expenses) income

Interest and debt expense	(29)		(17)
Loss on early extinguishment of debt	(5)		—
Loss from investment in unconsolidated subsidiary	(2)		(4)
Other non-operating (expenses) income	1		(6)
Income before income taxes	483		11
Income tax provision	(138)		(3)
Net income (loss)	$	345	$	8

Energy operating costs — Energy operating costs for the three months ended September 30, 2024 were $92 million, which was an increase of $51 million from $41 million for the three months ended June 30, 2024. This increase was primarily due to additional energy costs and purchase injectant used in the operation of the Aera fields. Our energy operating costs for the three months ended September 30, 2024 include $45 million related to Aera's fields following the completion of the Aera Merger on July 1, 2024. Excluding Aera, energy operating costs for the three months ended September 30, 2024 were higher than the three months ended June 30, 2024 as the result of higher natural gas prices. For more information on natural gas market prices, see Prices and Realizations above.

Non-energy operating costs — Non-energy operating costs for the three months ended September 30, 2024 were $214 million, which was an increase of $102 million from $112 million for the three months ended June 30, 2024. The increase was predominately a result of the operation of the Aera fields after the Aera Merger. Our non-energy operating costs for the three months ended September 30, 2024 include $99 million related to Aera's fields following the completion of the Aera Merger on July 1, 2024. Excluding Aera, non-energy operating costs increased in the three months ended September 30, 2024 compared to the three months ended June 30, 2024 due to additional spending on downhole and surface maintenance.

General and administrative expenses — General and administrative (G&A) expenses were $106 million for the three months ended September 30, 2024 compared to $63 million for the three months ended June 30, 2024. The increase was primarily a result of an additional $46 million related to Aera for the period from July 1, 2024 through September 30, 2024. Excluding Aera, G&A costs were slightly lower in the three months ended September 30, 2024 compared to the three months ended June 30, 2024.

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.


	Three months ended
	September 30, 2024		June 30, 2024

	(in millions)
Exploration and production, corporate and other	$	104	$	60
Carbon management business	2		3
Total general and administrative expenses	$	106	$	63

Depreciation, depletion and amortization — Depreciation, depletion and amortization for the three months ended September 30, 2024 was $140 million compared to $53 million during the three months ended June 30, 2024. The increase was the result of a higher carrying value of our property, plant and equipment after the Aera Merger.

Asset impairments — We did not recognize an asset impairment for the three months ended September 30, 2024. During the three months ended June 30, 2024, we recognized a $13 million asset impairment for excess and obsolete materials and supplies related to our oilfield operations.

Taxes other than on income — Taxes other than on income for the three months ended September 30, 2024 were $85 million, which is an increase of $46 million from $39 million for the three months ended June 30, 2024. This increase was due to higher production taxes, ad valorem taxes and greenhouse gas expense related to acquiring Aera's operations. Excluding Aera, taxes other than income for the three months ended September 30, 2024 increased from the three months ended June 30, 2024 primarily due to higher greenhouse gas expense, partially offset by lower ad valorem taxes.

Accretion expense — Accretion expense for the three months ended September 30, 2024 was $31 million compared to $13 million for the three months ended June 30, 2024. The increase was primarily due to the addition of Aera's asset retirement liability assumed as of July 1, 2024 as part of the Aera Merger.

Other operating expenses, net — Other operating expenses, net increased $22 million to $73 million for the three months ended September 30, 2024 compared to $51 million for the three months ended June 30, 2024. The increase was predominantly due to transaction costs, including success-based fees, related to the Aera Merger and severance expense in the three months ended September 30, 2024. These increases were partially offset by lower costs related to energy purchased due to fewer days of Elk Hills power plant downtime during the three months ended September 30, 2024.

Income taxes – The income tax provision for the three months ended September 30, 2024 was $138 million (representing an effective tax rate of 29%), compared to a provision of $3 million (representing an effective tax rate of 27%) for the three months ended June 30, 2024.

Nine months ended September 30, 2024 compared to September 30, 2023

The following table presents our operating revenues for the nine months ended September 30, 2024 and September 30, 2023:


	Nine months ended
	September 30, 2024		September 30, 2023

	(in millions)
Oil, natural gas and NGL sales	$	1,711	$	1,672
Net gain (loss) from commodity derivatives	290		(131)
Revenue from marketing of purchased commodities	176		336
Electricity sales	120		169
Other revenue	24		29
Total operating revenues	$	2,321	$	2,075

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $1,711 million for the nine months ended September 30, 2024, which is an increase of $39 million compared to $1,672 million for the nine months ended September 30, 2023. This increase was predominately a result of additional sales of oil production from the Aera fields following completion of the Aera Merger on July 1, 2024. The effect of cash settlements on our commodity derivative contracts are excluded from the table below. The table below includes sales of natural gas we produce which is used by our Elk Hills power plant.


	Oil		NGLs		Natural Gas		Total Operations

	(in millions)
Nine months ended September 30, 2023	$	1,154	$	151	$	367	$	1,672
Change in realized prices	(11)		(3)		(265)		(279)
Change in production	362		(10)		(16)		336

Nine months ended September 30, 2024	$	1,505	$	138	$	86	$	1,729

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

Net gain (loss) from commodity derivatives — Net gain from commodity derivatives was $290 million for the nine months ended September 30, 2024 compared to a net loss of $131 million for the nine months ended September 30, 2023. As of July 1, 2024, we recorded a liability of $336 million for Aera's outstanding Brent-based derivative contracts. Due to a decline in forward oil prices between July 1, 2024 and September 30, 2024, we recognized a non-cash commodity derivative gain for these Aera hedges during the nine months ended September 30, 2024. The net gain (loss) from commodity derivatives primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each measurement period.

Payments on commodity derivatives were $35 million for the nine months ended September 30, 2024 compared to payments of $223 million for the nine months ended September 30, 2023. Payments on commodity derivatives for the nine months ended September 30, 2023 included settlements for hedges that were entered into at a lower commodity price due to the requirements of our Revolving Credit Facility at that time.


	Nine months ended
	September 30, 2024		September 30, 2023

	(in millions)
Non-cash commodity derivative gain	$	325	$	92


Net cash payments on settled commodity derivatives	(35)		(223)

Net gain (loss) from commodity derivatives	$	290	$	(131)

Revenue from marketing of purchased commodities — Revenue from marketing of purchased commodities was $176 million for the nine months ended September 30, 2024, which was a decrease of $160 million from $336 million during the nine months ended September 30, 2023. The decrease was primarily the result of lower natural gas prices in 2024 compared to 2023. This decrease was partially offset by higher sales of purchased crude oil used in our marketing activities in 2024 as compared to 2023. Revenue from marketing of purchased commodities net of costs related to marketing of purchased commodities was $36 million for the nine months ended September 30, 2024 compared to $154 million for the nine months ended September 30, 2023.

Electricity sales — Electricity sales decreased by $49 million to $120 million for the nine months ended September 30, 2024 compared to $169 million for the nine months ended September 30, 2023 due to lower prices in 2024 compared to the same prior year period. The decrease was partially offset by higher resource adequacy revenues in the nine months ended September 30, 2024 as compared to the prior comparative period.

The following table presents our operating and non-operating expenses and income for the nine months ended September 30, 2024 and 2023:


	Nine months ended
	September 30, 2024		September 30, 2023

	(in millions)
Operating expenses
Energy operating costs	$	186	$	258
Gas processing costs	12		14
Non-energy operating costs	445		364
General and administrative expenses	226		201
Depreciation, depletion and amortization	246		170
Asset impairment	13		3
Taxes other than on income	162		132
Exploration expense	2		2
Purchased natural gas marketing expense	140		182
Electricity generation expenses	31		85
Transportation costs	60		49
Accretion expense	56		35
Carbon management business expenses	36		20
Other operating expenses, net	161		42
Total operating expenses	1,776		1,557
Gain on asset divestitures	7		7
Operating income	552		525

Non-operating (expenses) income

Interest and debt expense	(59)		(43)
Loss on early extinguishment of debt	(5)		—
Loss from investment in unconsolidated subsidiary	(9)		(6)
Other non-operating (expense) income	(4)		5
Income before income taxes	475		481
Income tax provision	(132)		(105)
Net income	$	343	$	376

Energy operating costs — Energy operating costs for the nine months ended September 30, 2024 were $186 million, which was a decrease of $72 million from $258 million for the nine months ended September 30, 2023. This decrease was a result of lower natural gas prices in the nine months of 2024 compared to the same prior year period as well as lower costs related to the divestiture of our share of a non-operated field in December 2023. This decrease was partially offset by higher energy costs in nine months ended September 30, 2024 of which $45 million related to energy and purchase injectant for the Aera fields following the completion of the Aera Merger. For more information on our natural gas market prices, see Prices and Realizations above.

Non-energy operating costs — Non-energy operating costs were $445 million for the nine months ended September 30, 2024, which was an increase of $81 million from $364 million for the nine months ended September 30, 2023. The increase was predominately a result of the additional fields acquired in the Aera Merger. Non-energy operating costs for the nine months ended September 30, 2024 include $99 million related to Aera's operations. Excluding Aera, non-energy operating costs for the nine months ended September 30, 2024 were lower than the prior year period as a result of lower costs for downhole and surface maintenance and lower costs from more favorable vendor pricing for certain items in 2024 as a result of cost savings initiatives undertaken during 2023.

General and administrative expenses — General and administrative (G&A) expenses were $226 million for the nine months ended September 30, 2024, which was an increase of $25 million from $201 million for the nine months ended September 30, 2023. The increase in G&A expenses was primarily attributable to the Aera Merger. Excluding Aera, G&A expenses were lower in the nine months ended September 30, 2024 compared to the same prior year period as a result of reduced spending on information technology infrastructure and lower stock-based compensation expense. Stock-based compensation awards are discussed further below.


	Nine months ended
	September 30, 2024		September 30, 2023

	(in millions)
Exploration and production, corporate and other	$	219	$	191
Carbon management business	7		10
Total general and administrative expenses	$	226	$	201

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:


	Nine months ended
	September 30, 2024		September 30, 2023

	(in millions)
Cash-settled awards	$	8	$	11
Stock-settled awards	17		21
Total included in general and administrative expenses	$	25	$	32

Depreciation, depletion and amortization — Depreciation, depletion and amortization for the nine months ended September 30, 2024 was $246 million compared to $170 million during the nine months ended September 30, 2023. The increase was the result of a higher carrying value for our property, plant and equipment as a result of the Aera Merger.

Asset impairments — Asset impairments increased $10 million to $13 million for the nine months ended September 30, 2024 from $3 million for the nine months ended September 30, 2023. In the nine months ended September 30, 2024, our asset impairment related to the write-down of excess and obsolete materials and supplies inventory related to our oilfield operations. In the nine months ended September 30, 2023, our asset impairment related to the write-down of a property to fair value when it was classified as held for sale.

Taxes other than on income — Taxes other than on income were $162 million for the nine months ended September 30, 2024, which was an increase of $30 million from $132 million for the nine months ended September 30, 2023. This increase was due to higher production taxes, ad valorem taxes and greenhouse gas expense related to the Aera assets following the completion of the Aera Merger on July 1, 2024. Excluding Aera, taxes other than on income was lower for the nine months ended September 30, 2024 compared to the same period in 2023 primarily due to lower greenhouse gas expense.

Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $140 million for the nine months ended September 30, 2024, which was a decrease of $42 million from $182 million for the nine months ended September 30, 2023. The decrease primarily related to lower natural gas prices in 2024 compared to 2023.

Electricity generation expense — Electricity generation expenses for the nine months ended September 30, 2024 were $31 million, which was a decrease of $54 million from $85 million for the same prior year period. This decrease was primarily due to lower prices for natural gas as well as downtime at our Elk Hills power plant for maintenance.

Transportation costs — Transportation costs for the nine months ended September 30, 2024 were $60 million which is an increase of $11 million from $49 million for the nine months ended September 30, 2023. The increase in transportation costs was primarily a result of higher volumes transported as well as additional transportation contracts assumed in the Aera Merger.

Accretion expense — Accretion expense for the nine months ended September 30, 2024 was $56 million compared to $35 million for the nine months ended September 30, 2023. The increase was primarily due to the addition of the Aera asset retirement liability assumed as of July 1, 2024 as part of the Aera Merger.

Carbon management business expenses — Carbon management business expenses increased by $16 million to $36 million for the nine months ended September 30, 2024 from $20 million for the nine months ended September 30, 2023. The increase in carbon management business expenses was predominantly due to higher lease cost for easements and compensation-related expenses.

Other operating expenses, net — Other operating expenses, net increased $119 million to $161 million for the nine months ended September 30, 2024 compared to $42 million for the nine months ended September 30, 2023. The increase was primarily related to transaction and integration costs for the Aera Merger as well as additional expenses related to electricity purchased during the ongoing maintenance at our Elk Hills power plant. We also incurred higher severance costs in the nine months ended September 30, 2024 as a result of our headcount reduction compared to the same prior year period.

Interest and debt expense, net — Interest and debt expense, net was $59 million for the nine months ended September 30, 2024 compared to $43 million for the nine months ended September 30, 2023. The increase was predominately a result from higher interest expense from the issuance of our 2029 Senior Notes. In June 2024, we issued $600 million in aggregate principal amount of 8.25% senior notes due 2029 and in August 2024, we completed a follow-on offer of $300 million in aggregate principal amount for those notes.

Income taxes – The income tax benefit for the nine months ended September 30, 2024 was $132 million (representing an effective tax rate of 28%), compared to a provision of $105 million (representing an effective tax rate of 22%) for the nine months ended September 30, 2023. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes for more information on our 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 three months ended September 30, 2024 were for capital investments, repurchases of our common stock and dividends.

The following table summarizes our liquidity:



	September 30, 2024
	(in millions)
Available cash and cash equivalents (a)	$	213
Revolving Credit Facility:
Borrowing capacity	1,100

Outstanding letters of credit	(175)
Availability	$	925

Liquidity	$	1,138

(a) Excludes restricted cash of $28 million.

We recently amended our Revolving Credit Facility as described in Part I, Item 1 – Financial Statements, Note 4 Debt . We also intend to pursue financing options for our carbon management business that are separate from the rest of our business.

At current commodity prices and based upon our planned 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 the indentures for our 2026 Senior Notes and our 2029 Senior Notes, (iii) reduce 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.

Revolving Credit Facility and Recent Amendment

The borrowing base under our Revolving Credit Facility is redetermined semi-annually and was reaffirmed at $1.5 billion on November 1, 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 commitments from our lenders.

On November 1, 2024, we entered into a fifth amendment to our Revolving Credit Facility. The amendments included, among other things:

• increasing the amount of the revolving commitments by $50 million to $1,150 million to reflect changes to our lender group;

• extending the maturity date of the facility from July 31, 2027 to March 16, 2029;

• increasing our capacity to issue letters of credit from $250 million to $300 million; and

• other technical amendments.

For more information regarding our Revolving Credit Facility and the recent amendments, see Part I, Item 1 – Financial Statements, Note 4 Debt and Note 15 Subsequent Events.

Cash Flow Analysis

Cash flows from operating activities — For the nine months ended September 30, 2024, our operating cash flow decreased by $118 million to $404 million from $522 million in the same period in 2023. This decrease in operating cash flow was primarily driven by lower natural gas prices in California markets during the nine months ended September 30, 2024 compared to the same prior year period. Our average natural gas prices decreased $7.09 per Mcf from $9.85 per MMcf in the nine months ended September 30, 2023 to $2.76 per Mcf during the nine months ended September 30, 2024. Further, our natural gas production decreased by 22 MMcf/d from 136 MMcf/d in the nine months ended September 30, 2023 to 114 MMcf/d in the nine months ended September 30, 2024, also contributing to the decrease.

Partially offsetting the decrease related to natural as prices and volumes, our realized oil price with derivative settlements increased by $12.85 per barrel to $77.10 in the nine months ended September 30, 2024 from $64.25 in the same prior year period and our net oil production volumes increased 16 MBbl/d from 53 MBbl/d in the nine months ended September 30, 2023 to 69 MBbl/d in the nine months ended September 30, 2024 as a result of the addition of Aera in the third quarter of 2024.

Transaction and integration costs related to the Aera Merger decreased operating cash flow by $56 million in 2024.

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


	Nine months ended September 30,
		2024		2023

		(in millions)
Capital investments		$	(167)	$	(119)
Changes in accrued capital investments		8		(10)
Proceeds from divestitures, net		12		—
Purchase of a business, net of cash acquired		(853)		—
Acquisitions		(6)		(1)


Other, net		(4)		(3)
Net cash used in investing activities		$	(1,010)	$	(133)

In March 2024, we sold our 0.9-acre Fort Apache real estate property in Huntington Beach, California for $10 million. For more information on our divestitures, see Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions.

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


	Nine months ended September 30,
		2024		2023

		(in millions)
Proceeds from Revolving Credit Facility		$	30	$	—
Repayments of Revolving Credit Facility		(30)		—
Proceeds from 2029 Senior Notes, net		888		—


Repurchases of common stock (a)		(135)		(143)
Common stock dividends		(77)		(59)
Payments on equity-settled awards		(4)		—

Issuance of common stock		2		1
Bridge loan commitment costs		(5)		—
Debt repurchases		(303)		(5)
Debt amendment costs		(10)		(8)
Stock warrants exercised		37		—
Shares cancelled for taxes		(42)		(3)
Net cash provided by (used in) financing activities		$	351	$	(217)

(a) The total value of shares purchased reported on our statement of cash flows includes approximately $1 million in both the nine months ended September 30, 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.

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 $81 million of dividends paid in the nine months ended September 30, 2024, we paid $4 million of dividend equivalents accrued on our stock-based compensation awards. For more information on the terms of our stock-based compensation awards, refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 9 Stock-Based Compensation in our 2023 Annual Report.

2024 Capital Program

Our capital program is dynamic in response to commodity price volatility and permit availability while focusing on oil production and maximizing our free cash flow. Our capital investment for the nine months ended September 30, 2024 was $167 million inclusive of $25 million for capital investment related to Aera's operations since the July 1, 2024 acquisition date. We expect our capital program for the remainder of 2024 to range between $85 million and $105 million under current permitting conditions. Of this amount, $77 million to $90 million is related to oil and natural gas development, $5 million to $10 million is for carbon management projects and $3 million to $5 million is for corporate and other. We expect to run a one rig program for the remainder of 2024 executing projects using existing permits. Refer to Regulatory Updates above for more information on permitting.

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 nine months ended September 30, 2024. See Part I, Item 1 – Financial Statements, Note 6 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of September 30, 2024 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2023 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

Transactions Related to Our Common Stock

The following table is a summary of common stock issuances:


						Common Stock

Balance at December 31, 2023						68,693,885
Issued as part of the Aera Merger						21,315,707
Shares repurchased						(2,604,922)
Shares issued for exercised warrants						1,139,163
Other shares issued, net						917,840
Balance at September 30, 2024						89,461,673

Common Stock Issued as Part of the Aera Merger

In connection with the Aera Merger, as described in Part I, Item 1 – Financial Statements, Note 2 Aera Merger, on July 1, 2024 we entered into a registration rights agreement (Registration Rights Agreement) with the Sellers. In accordance with the Registration Rights Agreement, a total of 21,315,707 shares of common stock were registered pursuant to a registration statement on Form S-3 filed on August 5, 2024.

The Registration Rights Agreement contemplates that each Seller is subject to certain lock-up provisions whereby such Seller agreed not to transfer (1) any shares of common stock issued to such Seller to any non-affiliate until January 1, 2025; (2) more than one-third of the shares of common stock issued to such Seller to any non-affiliate until July 1, 2025; and (3) more than two-thirds of the shares of common stock issued to such Seller to any non-affiliate until January 1, 2026. The lock up provisions are subject to certain exceptions as more particularly described in the Registration Rights Agreement, included as Exhibit 10.4 thereto.

Dividends

On August 2, 2024, our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of $1.55 , payable to shareholders in quarterly increments of $0.3875 per share of common stock. The actual declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position.

On November 5, 2024 , our Board of Directors declared a quarterly cash dividend of $0.3875 per share of common stock. The dividend is payable to shareholders of record at the close of business on December 2, 2024 and is expected to be paid on December 16, 2024 .

Our Board of Directors declared the following cash dividends in each of the periods presented.


	Total Dividend		Rate Per Share
	(in millions)		($ per share)
2024
Three months ended March 31, 2024	$	21	$	0.31
Three months ended June 30, 2024	22		$	0.31
Three months ended September 30, 2024	34		$	0.3875
Nine months ended September 30, 2024	$	77
2023
Three months ended March 31, 2023	$	20	$	0.2825
Three months ended June 30, 2023	20		$	0.2825
Three months ended September 30, 2023	19		$	0.2825
Nine months ended September 30, 2023	$	59

In addition to dividends declared, we paid $4 million of dividend equivalents related to stock-based compensation awards which were settled in the nine months ended September 30, 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 $231 million to shareholders through dividends (excluding dividend equivalents). 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 $1.35 billion of our common stock through December 31, 2025. The aggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $614 million, excluding commissions and excise taxes on repurchases, as of September 30, 2024. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend or discontinue authorization of the program at any time. The 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 September 30, 2023	365,145	$	20	$	54.75
Three months ended September 30, 2024	835,319	$	42	$	50.23

Nine months ended September 30, 2023	3,407,655	$	143	$	41.69
Nine months ended September 30, 2024	2,604,922	$	135	$	51.33

Inception of Program (May 2021) through September 30, 2024	17,468,837	$	739	$	42.14

Note: The total value of shares purchased includes approximately $1 million in both the nine months ended September 30, 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.

Warrants

In October 2020, we reserved an aggregate 4,384,182 shares of our common stock for warrants for issuance upon the exercise of warrants, which were exercisable at $36 per share through October 28, 2024.

Divestitures, Acquisitions and Assets Held for Sale

See Part I, Item 1 – Financial Statements, Note 7 Divestitures, Acquisitions and Assets Held for Sale for information on our divestitures and acquisitions during the three and nine months ended September 30, 2024 and 2023.

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 at September 30, 2024 and December 31, 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 5 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 2023 Annual Report.

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,” “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

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

• fluctuations in commodity prices, including supply and demand considerations for our products and services, and the impact of such fluctuations on revenues and operating expenses;

• 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 military conflicts in Israel, Lebanon, Ukraine and Yemen and the Red Sea;

• the ability to successfully execute integration efforts in connection with our merger with Aera Energy LLC, and achieve projected synergies and ensure that such synergies are sustainable;

• 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, EPA and other governmental permits and approvals necessary for drilling or development activities or our carbon management business; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of our products;

• the efforts of activists to delay prevent oil and gas activities or the development of our carbon management business through a variety of tactics, including litigation;

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

• changes in business strategy and our capital plan;

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

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

• the recoverability of resources and unexpected geologic conditions;

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

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

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

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

• any failure of risk management;

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

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

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

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

• reorganization or restructuring of our operations;

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

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

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

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

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

• uncertainty around the accounting of emissions and our ability to successfully gather and verify emissions data and other environmental impacts;

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

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

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

• changes in interest rates;

• Our access to and the terms of credit in commercial banking and capital markets,

including our ability to refinance our debt or obtain separate financing for our carbon management business;

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

• effects of hedging transactions;

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

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

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

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

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

Item 3 Quantitative and Qualitative Disclosures About Market Risk

For the three and nine months ended September 30, 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 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 PSCs. We maintain a commodity hedging program focused on hedging crude oil sales and natural gas purchases to help protect our cash flows, margins and capital program from the volatility of commodity prices. As of September 30, 2024, we had a net liability of $6 million for our commodity derivative positions which are carried at fair value. For more information on our derivative positions as of September 30, 2024 , refer to Part I, Item 1 – Financial Statements, Note 6 Derivatives. We have price exposure for natural gas we purchase and use in our business. We used natural gas to generate electricity for our operations and higher natural gas prices will also result in an increase to our electricity costs.

Counterparty Credit Risk

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

As of September 30, 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 September 30, 2024 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

Interest-Rate Risk

Changes in interest rates may affect the amount of interest we pay on our long-term debt. We had no variable-rate debt outstanding as of September 30, 2024 . Our 2026 Senior Notes bear interest at a fixed rate of 7.125% per annum. Our 2029 Senior Notes bear interest at a fixed rate of 8.250% per annum.

Item 4 Controls 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 September 30, 2024. As disclosed in Part I, Item 1 – Financial Statements, Note 2 Aera Merger , we completed the Aera Merger on July 1, 2024. As part of the ongoing integration of Aera, we are in process of incorporating the controls and related procedures of Aera. Management's evaluation of our disclosure controls and procedures as of September 30, 2024 excludes an evaluation of the disclosure controls and procedures of Aera.

Other than incorporating Aera's controls, there were no other changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the three months ended September 30, 2024 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION

Item 1 Legal Proceedings

For additional information regarding legal proceedings, see Item 1 – Financial Statements, Note 4 Lawsuits, Claims, Commitments and Contingencies in the Notes to the Condensed Consolidated Financial Statements included in Part I of this Form 10-Q, Part I, Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Lawsuits, Claims, Commitments and Contingencies in this Form 10-Q, and Part I, Item 3, Legal Proceedings in our 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 2023 Annual Report. Except as set forth below, there were no material changes to those risk factors during the three months ended September 30, 2024.

We may face increased local restrictions on oil and gas exploration and production operations or even be prohibited from operating in certain areas as a result of recently enacted California legislation .

On September 25, 2024, Assembly Bill 3233 (AB 3233) was enacted which authorizes local governments to limit methods for, or even prohibit, oil and gas operations or development within their jurisdiction, including with respect to existing operations. Prior to the passage of this law, certain local governments within California had previously taken steps to limit oil and gas operations that were struck down by California courts. Monterey County previously sought to ban only new production and prohibit the use of wastewater injection as a production method. The City and County of Los Angeles previously sought to both ban new wells and phaseout existing wells over a certain period of time. Although both those local measures were struck down in court, following the adoption of AB 3233, certain legal arguments used to challenge these local actions are no longer valid and it is possible that these or other local governments in places where we operate may pass similar regulations. For the three months ended September 30, 2024, approximately 12% of our gross production is located in Los Angeles County and approximately 3% is in Monterey County. It is difficult to predict how local governments in California may choose to exercise their new authority under AB 3233.

While there may be future legal challenges to AB 3233 and any local ordinances enacted thereunder, we cannot predict whether or not such challenges will be successful. Notwithstanding any potential claims for regulatory takings we may have in the event local jurisdictions seek to prohibit any of our existing operations, to the extent that the local governments in the areas where we operate in California enact new restrictions or prohibitions with respect to oil and gas exploration and production activities, we could face increased operating costs, loss of revenues, and other material and adverse impacts to our business and results of operations.

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 $1.35 billion of our common stock through 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 September 30, 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)
July 1, 2024 - July 31, 2024	—	$	—	—	$	—
August 1, 2024 - August 31, 2024	256,953	$	50.64	256,953	—
September 1, 2024 - September 30, 2024	578,366	$	50.05	578,366	—
Total	835,319	$	50.23	835,319	$	—

(a) The total value of shares that may yet be purchased under the Share Repurchase Program totaled $614 million as of September 30, 2024.

Item 5 Other Disclosures

Rule 10b5-1 Trading Arrangements

On September 12, 2024 , Omar Hayat , our Executive Vice President of Operations, entered into a 10b5-1 trading arrangement intended to satisfy the affirmative defense conditions of Rule 10b5-1 (c). The trading arrangement will be in effect from December 12, 2024 to March 12, 2025 . An aggregate of up to 16,016 shares may be sold pursuant to this trading arrangement.

On September 12, 2024 , Michael L. Preston , our Executive Vice President , Chief Strategy Officer and General Counsel entered into a 10b5-1 trading arrangement intended to satisfy the affirmative defense conditions of Rule 10b5-1 (c). The trading arrangement will be in effect from December 12, 2024 to January 9, 2025 . An aggregate of up to 83,000 shares may be sold pursuant to this trading arrangement.

During the three months ended September 30, 2024, no other directors or officers adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

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).

4.1			Indenture, dated June 5, 2024, by and among the Company, the Guarantors and the Trustee (filed as Exhibit 4.1 to Registrant's Current Report on Form 8-K filed on June 5, 2024 and incorporated herein by reference).

4.2			Supplemental Indenture to the 2026 Indenture, dated as of July 1, 2024, by and among Aera Energy LLC, a California limited liability company, Aera Energy Services Company, a Delaware corporation, Aera Federal LLC, a Delaware limited liability company, Belridge Farms & Packing LLC, a California limited liability company, Green Gate San Ardo LLC, a Delaware limited liability company, Terrain Technology Inc., a California corporation, Green Gate Intermediate LLC, a Delaware limited liability company, Green Gate Resources E LLC, a Delaware limited liability company, Green Gate Resources S LLC, a Delaware limited liability company, Green Gate Resources Holdings LLC, a Delaware limited liability company, Green Gate Resources Parent LLC, a Delaware limited liability company, Petra Merger Sub S, LLC, a Delaware limited liability company, the other guarantors party thereto, CRC and Wilmington Trust, National Association, as trustee (filed as Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed on July 1, 2024 and incorporated herein by reference).

4.3			Supplemental Indenture to the 2029 Indenture, dated as of July 1, 2024, by and among Aera Energy LLC, a California limited liability company, Aera Energy Services Company, a Delaware corporation, Aera Federal LLC, a Delaware limited liability company, Belridge Farms & Packing LLC, a California limited liability company, Green Gate San Ardo LLC, a Delaware limited liability company, Terrain Technology Inc., a California corporation, Green Gate Intermediate LLC, a Delaware limited liability company, Green Gate Resources E LLC, a Delaware limited liability company, Green Gate Resources S LLC, a Delaware limited liability company, Green Gate Resources Holdings LLC, a Delaware limited liability company, Green Gate Resources Parent LLC, a Delaware limited liability company, Petra Merger Sub S, LLC, a Delaware limited liability company, the other guarantors party thereto, CRC and Wilmington Trust, National Association, as trustee (filed as Exhibit 10.7 to the Registrant’s Current Report on Form 8-K filed on July 1, 2024 and incorporated herein by reference).

4.4			Second Supplemental Indenture to the 2029 Indenture, dated as of August 22, 2024, by and among the guarantors party thereto, CRC and Wilmington Trust, National Association, as Trustee (filed as Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on August 22, 2024 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			Fourth Amendment to Amended and Restated Credit Agreement, dated as of July 1, 2024, by and among CRC, the guarantors party thereto, the banks, financial institution and other lending institutions from time to time parties as lenders thereto, and Citibank, N.A., as administrative agent and collateral agent (filed as Exhibit 10.5 to Registrant's Current Report on Form 8-K filed on June 28, 2024 and incorporated herein by reference).



10.3*			Fifth Amendment to Amended and Restated Credit Agreement, dated as of November 1, 2024, by and among CRC, the guarantors party thereto, the banks, financial institution and other lending institutions from time to time parties as lenders thereto, and Citibank, N.A., as administrative agent and collateral agent.

10.4			Registration Rights Agreement, by and between CRC and the Sellers, dated as of July 1, 2024 (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on July 1, 2024 and incorporated herein by reference).

10.5			Stockholder Agreement, by and between CRC and IKAV Seller, dated as of July 1, 2024 (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on July 1, 2024 and incorporated herein by reference).

10.6			Stockholder Agreement, by and between CRC and CPP Seller, dated as of July 1, 2024 (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on July 1, 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

SIGNATURES

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


			CALIFORNIA RESOURCES CORPORATION


DATE:	November 6, 2024	/s/ Noelle M. Repetti
		Noelle M. Repetti
		Senior Vice President and Controller
		(Principal Accounting Officer)

TABLE OF CONTENTS

Part I, Item 3, Legal Proceedings Item 1A Risk Factors Item 2 Unregistered Sales Of Equity Securities and Use Of Proceeds Item 5 Other Disclosures Item 6 Exhibits

Exhibits

CRC 10-Q Quarter ended Sept. 30, 2024

Exhibits