CRC 10-Q Quarterly Report Sept. 30, 2025

CALIFORNIA RESOURCES CORP

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crc-20250930

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, 2025

☐ 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 September 30, 2025 was 83,711,931 .

California Resources Corporation and Subsidiaries

Table of Contents


	Page
Part I
Item 1	Financial Statements	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements of Comprehensive Income	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
	Pending Berry Merger	34
	Business Environment and Industry Outlook	34
	Regulatory Updates	36
	Statements of Operations Analysis	37
	Results of Our Oil and Natural Gas Operations	45
	Results of Our Carbon Management Segment	49
	Liquidity and Capital Resources	49
	Divestitures and Assets Held for Sale	52
	Lawsuits, Claims, Commitments and Contingencies	53
	Critical Accounting Estimates and Significant Accounting and Disclosure Changes	53
	Forward-Looking Statements	54
Item 3	Quantitative and Qualitative Disclosures About Market Risk	55
Item 4	Controls and Procedures	56

Part II
Item 1	Legal Proceedings	57
Item 1A	Risk Factors	57
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	58
Item 5	Other Disclosures	59
Item 6	Exhibits	60

GLOSSARY AND SELECTED ABBREVIATIONS

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

• AB - Assembly Bill.

• 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.

• CAISO - California Independent System Operator.

• 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.

• MHp - One thousand horsepower.

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

• MMBoe - One million barrels of oil equivalent.

• MMBtu - One million British thermal units.

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

• MMT - Million metric tons.

• MMTPA - Million metric tons per annum.

• MW - Megawatts of power.

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

• NYMEX - The New York Mercantile Exchange.

• OCTG - Oil country tubular goods.

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

• OPEC - Organization of the Petroleum Exporting Countries.

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

• PHMSA - Pipeline and Hazardous Materials Safety Administration.

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

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

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

• PSCs - Production-sharing contracts.

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

• Responsible Net Zero – Refers to our net zero emissions goal adopted by our Board of Directors in May 2025.

• SB - Senate Bill.

• 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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of September 30, 2025 and December 31, 2024

(in millions, except share data)


	September 30,		December 31,
	2025		2024
	(unaudited)		(audited)
CURRENT ASSETS
Cash and cash equivalents	$	196	$	372
Trade receivables	286		330
Inventory	94		90
Assets held for sale	7		10
Receivable from affiliate	26		46
Other current assets, net	203		176
Total current assets	812		1,024
PROPERTY, PLANT AND EQUIPMENT	6,966		6,738
Accumulated depreciation, depletion and amortization	( 1,436 )		( 1,058 )
Total property, plant and equipment, net	5,530		5,680
INVESTMENT IN UNCONSOLIDATED SUBSIDIARIES	102		86
DEFERRED INCOME TAXES	27		73
OTHER NONCURRENT ASSETS	280		272
TOTAL ASSETS	$	6,751	$	7,135


CURRENT LIABILITIES
Current portion of long-term debt	$	122	$	—


Accounts payable	316		369


Accrued liabilities	479		611

Total current liabilities	917		980
NONCURRENT LIABILITIES
Long-term debt, net	889		1,132

Asset retirement obligations	965		995
Deferred tax liabilities	212		113
Other long-term liabilities	325		377



STOCKHOLDERS' EQUITY
Preferred stock ( 20,000,000 shares authorized at $ 0.01 par value) no shares outstanding at September 30, 2025 and December 31, 2024	—		—
Common stock ( 200,000,000 shares authorized at $ 0.01 par value) ( 105,063,163 and 109,613,585 shares issued; 83,711,931 and 91,100,322 shares outstanding at September 30, 2025 and December 31, 2024)	1		1
Treasury stock ( 21,351,232 shares held at cost at September 30, 2025 and 18,513,263 shares held at cost at December 31, 2024)	( 922 )		( 796 )
Additional paid-in capital	2,365		2,578
Retained earnings	1,927		1,680
Accumulated other comprehensive income	72		75


Total stockholders' equity	3,443		3,538
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	6,751	$	7,135

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations (unaudited)

For the three and nine months ended September 30, 2025 and 2024

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


	Three months ended September 30,				Nine months ended September 30,
	2025		2024		2025		2024
REVENUES
Oil, natural gas and natural gas liquids sales	$	715	$	870	$	2,231	$	1,711
Net (loss) gain from commodity derivatives	( 23 )		356		140		290
Revenue from marketing of purchased commodities	58		51		178		176
Electricity revenue	101		69		181		120
Other revenue	4		7		15		24
Total operating revenues	855		1,353		2,745		2,321

OPERATING EXPENSES
Operating costs	316		311		927		643
General and administrative expenses	87		106		238		226
Depreciation, depletion and amortization	123		140		382		246

Asset impairment	2		—		2		13
Taxes other than on income	70		85		187		162

Costs related to marketing of purchased commodities	44		43		135		140
Electricity generation expenses	11		9		26		31
Transportation costs	19		23		59		60
Accretion expense	28		31		85		56
Net loss on natural gas purchase derivatives	27		9		24		11
Measurement period adjustments, net	—		—		1		—
Other operating expenses, net	29		78		127		188
Total operating expenses	756		835		2,193		1,776
(Loss) gain on asset divestitures	( 1 )		—		( 1 )		7

OPERATING INCOME	98		518		551		552

NON-OPERATING (EXPENSES) INCOME

Interest and debt expense, net	( 25 )		( 29 )		( 77 )		( 59 )
Loss on early extinguishment of debt	—		( 5 )		( 1 )		( 5 )
Loss from investment in unconsolidated subsidiaries	( 2 )		( 2 )		( 3 )		( 9 )
Other non-operating income (expense), net	4		1		9		( 4 )
INCOME BEFORE INCOME TAXES	75		483		479		475
Income tax provision	( 11 )		( 138 )		( 128 )		( 132 )
NET INCOME	$	64	$	345	$	351	$	343






Net income per share
Basic	$	0.76	$	3.86	$	4.00	$	4.54
Diluted	$	0.76	$	3.78	$	3.97	$	4.42

Weighted-average common shares outstanding
Basic	83.7		89.4		87.8		75.5
Diluted	84.4		91.2		88.4		77.6

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Comprehensive Income (unaudited)

For the three and nine months ended September 30, 2025 and 2024

(in millions)


	Three months ended September 30,				Nine months ended September 30,
	2025		2024		2025		2024
Net income	$	64	$	345	$	351	$	343
Other comprehensive income (loss) (a) :
Recognition of net actuarial loss due to settlement	1		—		1		—
Actuarial gain associated with pension and postretirement plans, net of tax	—		9		( 1 )		9
Amortization of prior service cost credit included in net periodic benefit cost, net of tax	( 1 )		( 4 )		( 3 )		( 6 )

Comprehensive income	$	64	$	350	$	348	$	346

(a) Tax effects of the actuarial gain associated with pension and postretirement plans and amortization of prior service cost credit were insignificant for the three and nine months ended September 30, 2025 and 2024.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Stockholders' Equity (unaudited)

For the three and nine months ended September 30, 2025 and 2024

(in millions)


	Three months ended September 30, 2025
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, June 30, 2025	$	1	$	( 922 )	$	2,359	$	1,897	$	72	$	3,407
Net income	—		—		—		64		—		64

Share-based compensation	—		—		6		—		—		6






Cash dividend	—		—		—		( 33 )		—		( 33 )
Shares cancelled for taxes	—		—		( 1 )		—		—		( 1 )

Other	—		—		1		( 1 )		—		—
Balance, September 30, 2025	$	1	$	( 922 )	$	2,365	$	1,927	$	72	$	3,443


	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	—		—		—		( 36 )		—		( 36 )

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

Balance, September 30, 2024	$	1	$	( 739 )	$	2,479	$	1,683	$	77	$	3,501

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


	Nine months ended September 30, 2025
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, December 31, 2024	$	1	$	( 796 )	$	2,578	$	1,680	$	75	$	3,538
Net income	—		—		—		351		—		351

Share-based compensation	—		—		20		—		—		20


Repurchases of common stock	—		( 126 )		( 228 )		—		—		( 354 )


Issuance of common stock	—		—		6		—		—		6
Cash dividend	—		—		—		( 104 )		—		( 104 )
Shares cancelled for taxes	—		—		( 12 )		—		—		( 12 )
Other comprehensive income, net of tax	—		—		—		—		( 3 )		( 3 )
Other	—		—		1		—		—		1
Balance, September 30, 2025	$	1	$	( 922 )	$	2,365	$	1,927	$	72	$	3,443


	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	—		—		—		( 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

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (unaudited)

For the three and nine months ended September 30, 2025 and 2024

(in millions)


	Three months ended September 30,				Nine months ended September 30,
	2025		2024		2025		2024
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	64	$	345	$	351	$	343
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	123		140		382		246
Asset impairments	2		—		2		13
Deferred income tax provision	35		90		76		84

Net loss (gain) from commodity derivatives	50		( 347 )		( 116 )		( 279 )
Net proceeds (payments) on settled commodity derivatives	6		( 29 )		( 12 )		( 53 )
Net loss on early extinguishment of debt	—		5		1		5
Gain on asset divestitures	1		—		1		( 7 )



Other non-cash charges to income, net	41		45		110		97
Net changes in operating assets and liabilities	( 43 )		( 29 )		( 165 )		( 45 )
Net cash provided by operating activities	279		220		630		404

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	( 91 )		( 79 )		( 202 )		( 167 )
Changes in accrued capital investments	5		6		( 10 )		8
Proceeds from asset divestitures	1		—		2		12
Purchase of a business, net of cash acquired	—		( 853 )				( 853 )



Acquisitions	—		—		—		( 6 )
Other, net	( 2 )		( 2 )		( 7 )		( 4 )
Net cash used in investing activities	( 87 )		( 928 )		( 217 )		( 1,010 )

CASH FLOW FROM FINANCING ACTIVITIES




Proceeds from Revolving Credit Facility	150		—		150		30
Repayments of Revolving Credit Facility	( 150 )		( 30 )		( 150 )		( 30 )
Proceeds from 2029 Senior Notes, net	—		298		—		888
Repurchases of common stock	( 34 )		( 42 )		( 352 )		( 135 )
Common stock dividends	( 32 )		( 34 )		( 102 )		( 77 )
Dividend equivalents on equity-settled awards	—		—		( 1 )		( 4 )




Issuance of common stock	—		—		2		2
Bridge loan commitments	—		—		—		( 5 )

Stock warrants exercised	—		37		—		37
Debt amendment costs	—		( 7 )		—		( 10 )
Shares cancelled for taxes	( 1 )		—		( 12 )		( 42 )
Debt issuance costs	( 1 )		—		( 1 )		—
Debt redemption	—		( 303 )		( 123 )		( 303 )
Other	—		( 1 )		—		—
Net cash (used in) provided by financing activities	( 68 )		( 82 )		( 589 )		351
Increase (decrease) in cash and cash equivalents	124		( 790 )		( 176 )		( 255 )
Cash and cash equivalents—beginning of period	72		1,031		372		496
Cash and cash equivalents—end of period	$	196	$	241	$	196	$	241

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 (Unaudited)

September 30, 2025

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.

On July 1, 2024, pursuant to the Agreement and Plan of Merger, dated as of February 7, 2024, we obtained all of the ownership interests in Aera Energy LLC (Aera) in an all-stock transaction (Aera Merger). Our consolidated results of operations include the results of Aera beginning July 1, 2024, the closing date of the Aera Merger. The Aera Merger significantly impacted the comparability of our financial results for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024. See Note 2 Business Combinations for transaction details.

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.

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, 2024 (2024 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.

Recently Issued but not Adopted Accounting and Disclosure Changes

In September 2025, the Financial Accounting Standards Board’s (FASB) issued amendments to accounting requirements for Internal-Use Software (ASC 350-40). The amendment changes the framework for capitalizing internal-use software costs and adds disclosure requirements. The rule becomes effective for fiscal years beginning after December 15, 2027, but early adoption is permitted. We intend to apply the amendments on a prospective basis, but adoption on a retrospective basis is permitted. We do not expect the adoption of the rule to have a significant impact on our financial statements.

NOTE 2 BUSINESS COMBINATIONS

Pending Berry Merger

On September 14, 2025, we entered into a definitive agreement and plan of merger (the Berry Merger Agreement) to combine with Berry Corporation (bry) (Berry) in an all-stock transaction (Berry Merger). Berry is an independent upstream energy company that operates in two business segments: (i) oil and natural gas and (ii) well servicing and abandonment services. Berry's oil and gas assets are located in California and Utah. We expect the transaction will add high quality, oil-weighted, mostly conventional proved developed reserves and sustainable cash flows to our operations.

Pursuant to the Berry Merger Agreement, on the effective date of the merger, we will issue 0.0718 shares of our common stock for each outstanding share of Berry stock. Upon closing of the Berry Merger, we expect Berry's outstanding long-term debt to be repaid and the underlying credit agreement to be terminated. We expect to repay a significant portion of this indebtedness with proceeds from our 2034 Senior Notes, which closed in October 2025. Berry's Revolving Credit Facility is also expected to be terminated at closing. For more information on the 2034 Senior Notes, refer to Note 16 Subsequent Events .

Closing of the Berry Merger is subject to certain conditions, including, among others, adoption of the Berry Merger Agreement by its stockholders, expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, prior authorization by the Federal Energy Regulatory Commission under Section 203 of the Federal Power Act and other customary closing conditions.

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 added significant proved developed reserves to CRC. In connection with the closing of the Aera Merger, we issued shares of common stock to the former Aera owners. 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.

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 former owners of Aera owned 24 % of CRC. For more information on the 2029 Senior Notes, refer to Note 4 Debt.

We have measured assets and liabilities at acquisition date fair value on a nonrecurring basis. See Note 2 Aera Merger in our Quarterly Report on Form 10-Q for the six months ended June 30, 2025, for information on our final purchase price allocation.

The following table summarizes the consideration transferred:


	Merger Consideration
	(in millions, except share and per share data)
Shares of common stock (dividend adjusted)	21,422,972
Common stock per share fair value on July 1, 2024	$	53.28
Fair value of share consideration	1,141
Settlement of Aera debt	990
Purchase price settlement	( 10 )
Total purchase consideration	$	2,121

Supplemental Pro Forma Information

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



		Nine months ended September 30,
		2024

	(in millions)
Total operating revenue		$	3,006
Net income		$	290

Net income per share
Basic		$	3.23
Diluted		$	3.16

This supplemental pro forma financial 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, 2024, nor is it necessarily indicative of future operating results of the combined entity. The pro forma financial information for the nine months ended September 30, 2024 is a result of combining our nine months statements of operations with Aera's pre-merger results from January 1, 2024 through June 30, 2024 and pro forma adjustments include estimates and assumptions based on currently available information. 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. 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. We also included pro forma adjustments for certain compensation-related costs and transaction costs we incurred related to the Aera Merger. Management believes the estimates and assumptions are reasonable, and the relative effects of the Aera Merger are properly reflected.

NOTE 3 INVESTMENTS AND RELATED PARTY TRANSACTIONS

The following tables present changes to our investments in unconsolidated subsidiaries for the periods presented:


	Carbon TerraVault JV
	(in millions)
Investment, December 31, 2024	$	27



Net loss	( 4 )
Contributions	26
Investment, September 30, 2025	$	49


	Midway Sunset Cogeneration Company
	(in millions)





Investment, December 31, 2024	$	59
Adjustment to the preliminary purchase price allocation in the Aera Merger	( 7 )
Net income	1

Investment, September 30, 2025	$	53

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. The Carbon TerraVault JV holds rights to inject CO 2 into the 26R reservoir in our Elk Hills field for permanent CO 2 storage (26R reservoir).

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 $ 107 million at December 31, 2024 and $ 115 million at September 30, 2025 , inclusive of interest. The amount payable to Brookfield under the put and call rights, if exercised, includes additional capital contributions made by Brookfield to develop the 26R storage reservoir, inclusive of interest. This payment would differ from the contingent liability currently recognized because the contingent liability reported in other long-term liabilities on our condensed consolidated balance sheet relates solely to the initial investment by Brookfield and does not include capital contributions made for ongoing development activities of the 26R reservoir.

The table below presents the summarized financial information related to our equity method investment in the Carbon TerraVault JV (and does 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,
	2025		2024

	(in millions)

Receivable from affiliate (a)	$	26	$	46
Other long-term liabilities (b)	$	115	$	107

(a) At September 30, 2025, the amount of $ 26 million includes the remaining $ 17 million of Brookfield's first and second installments of their initial investment which is available to us and $ 9 million related to the Master Service Agreement (MSA) and vendor reimbursements. At December 31, 2024, the amount of $ 46 million includes $ 43 million remaining of Brookfield's initial contribution available to us and $ 3 million related to the MSA and vendor reimbursements.

(b) Other long-term liabilities include the contingent liability related to the Carbon TerraVault JV put and call rights.

We recognized a loss of $ 2 million and $ 4 million for the three and nine months ended September 30, 2025, respectively, and a loss of $ 3 million and $ 10 million for the three and nine months ended September 30, 2024, respectively, related to our investment in the Carbon TerraVault JV.

During the three and nine months ended September 30, 2025, we performed well abandonment work to prepare the 26R reservoir for injection of CO 2 and sought reimbursement in the amounts of $ 2 million and $ 9 million, respectively, from the Carbon TerraVault JV. During the three and nine months ended September 30, 2024, we performed well abandonment work and sought reimbursement in the amounts of $ 4 million and $ 13 million, respectively, from the Carbon TerraVault JV. We recorded these reimbursements as a reduction to property, plant and equipment, net on our condensed consolidated balance sheets.

Midway Sunset Cogeneration Company

The Aera Merger led to our partial ownership of Midway Sunset Cogeneration Company, which owns, manages, and operates a cogeneration facility in Kern County, California. The Midway Sunset Cogeneration Company is owned 50 % by us and 50 % by San Joaquin Energy Company, a subsidiary of NRG Energy Inc. There are no significant transactions between us and Midway Sunset Cogeneration Company. Our 50 % share of the net income related to our investment in Midway Sunset Cogeneration Company was insignificant for the three and nine months ended September 30, 2025 and 2024.

NOTE 4 DEBT

As of September 30, 2025 and December 31, 2024, our long-term debt consisted of the following:



	September 30,		December 31,
	2025		2024		Interest Rate	Maturity

	(in millions)

Revolving Credit Facility	$	—	$	—	SOFR plus 2.50 %- 3.50 % ABR plus 1.50 %- 2.50 % (a)	March 16, 2029

2026 Senior Notes	122		245		7.125 %	February 1, 2026
2029 Senior Notes	900		900		8.250 %	June 15, 2029
Principal amount	1,022		$	1,145
Unamortized debt discount and issuance costs	( 14 )		( 16 )
Unamortized premium	3		3
Total debt, net	1,011		1,132
Less: Current maturities	122		—
Long-term debt, net	$	889	$	1,132

(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 % .

Revolving Credit Facility

Our Amended and Restated Credit Agreement, dated April 26, 2023 (Revolving Credit Facility), consists of a senior revolving loan facility with an aggregate commitment of $ 1.15 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 includes a sub-limit of $ 300 million for the issuance of letters of credit. As of September 30, 2025, $ 176 million letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters. As of September 30, 2025, we had $ 974 million of availability on our Revolving Credit Facility after taking into account $ 176 million in letters of credit outstanding. Our borrowing base of $ 1.5 billion is redetermined semi-annually and was re-affirmed in October 2025.

In connection with the Berry Merger Agreement in September 2025, we entered into a sixth amendment to our Revolving Credit Facility to, among other things, allow for the incurrence of the 2034 Senior Notes without a corresponding reduction in our existing borrowing base.

See Note 16 Subsequent Events for more information on our 2034 Senior Notes and the seventh amendment to our Revolving Credit Facility.

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,
	2025		2024

	(in millions)

Fixed rate debt
2026 Senior Notes	$	122	$	245
2029 Senior Notes	939		913
Fair Value of Long-Term Debt	$	1,061	$	1,158

Other

As of September 30, 2025, we were in compliance with all financial and other debt covenants under our Revolving Credit Facility, 2026 Senior Notes and 2029 Senior Notes.

Note Redemptions

In February 2025, we redeemed $ 123 million of our 7.125 % senior notes due 2026 (2026 Senior Notes) at 100 % of the principal amount, resulting in an extinguishment loss in the amount of $ 1 million for the write-off of unamortized debt issuance costs. See Note 16 Subsequent Events for additional information on the redemption of the remaining balance of our 2026 Senior Notes in October 2025.

NOTE 5 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

We are party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. 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, 2025 and December 31, 2024 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 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. In September 2025, the parties amended the cost sharing agreement to include well abandonment work. As of September 30, 2025, we recognized a liability of $ 4 million, included in accrued liabilities in our condensed consolidated balance sheet related to this abandonment work. For the three and nine months ended September 30, 2025, other operating expenses, net on our condensed consolidated statement of operations includes $ 5 million and $ 7 million, respectively, for our ongoing share of maintenance costs and well abandonment work. We continue to challenge the BSEE order.

In 2023 and 2024, the California Geologic Energy Management Division (CalGEM) plugged and abandoned approximately 120 "orphaned" oil and gas wells located in Cat Canyon, Santa Barbara County, at an aggregate cost of $ 25 million. These wells had previously been operated by us prior to being sold to their current operators. CalGEM is seeking to recover these costs from us due to our prior operatorship of the wells, and we are disputing these claims. In connection with this dispute, we were required to remit $ 25 million to CalGEM under protest pending the outcome of this matter. For the nine months ended September 30, 2025, other operating expenses, net on our condensed consolidated statement of operations includes $ 25 million related to this matter.

NOTE 6 DERIVATIVES

We enter into commodity derivative contracts to help protect our cash flows, margins and capital program from the volatility of commodity prices. We primarily hedge a portion of our forecasted oil production and purchase natural gas used in our steamflood operations. We did not have any derivative instruments designated as accounting hedges as of and for the three and nine months ended September 30, 2025 and 2024. 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, 2025:


	Q4 2025		Q1 2026		Q2 2026		Q3 2026		Q4 2026		2027		2028
Sold Calls
Barrels per day	29,000		35,000		35,000		35,000		35,000		—		—
Weighted-average price per barrel	$	87.13	$	83.86	$	83.86	$	83.86	$	83.86	$	—	$	—

Purchased Puts
Barrels per day	29,000		35,000		35,000		35,000		35,000		—		—
Weighted-average price per barrel	$	61.72	$	61.14	$	61.14	$	61.14	$	61.14	$	—	$	—

Swaps
Barrels per day	43,376		36,444		29,399		28,369		27,703		39,382		1,697
Weighted-average price per barrel	$	69.86	$	68.98	$	68.03	$	67.51	$	66.99	$	64.80	$	65.00

At September 30, 2025, we also held the following swaps to hedge purchased natural gas used in our operations as shown in the table below.


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

SoCal Border
MMBtu per day	22,408		20,350		13,250		10,750		9,908		—		—
Weighted-average price per MMBtu	$	3.53	$	5.18	$	4.82	$	4.83	$	4.84	$	—	$	—

NWPL Rockies
MMBtu per day	51,750		51,750		51,750		51,750		51,750		38,546		1,576
Weighted-average price per MMBtu	$	4.22	$	4.67	$	3.64	$	3.63	$	4.22	$	4.08	$	3.95

In the three and nine months ended September 30, 2025 and 2024, we also had a limited number of derivative contracts related to our natural gas marketing activities that were intended to lock in locational price spreads. These derivative contracts were not significant to our results of operations or financial statements taken as a whole.

The outcomes of the derivative positions shown in the tables above 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 – with respect to swaps for crude oil, 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. With respect to swaps for purchased natural gas, we receive settlement payments for prices above the indicated weighted-average price per MMBtu and we make settlement payments for prices below the weighted-average price per MMBtu.

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 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,
	2025		2024		2025		2024

	(in millions)				(in millions)
Non-cash commodity derivative (loss) gain	$	( 32 )	$	373	$	130	$	325
Net proceeds (settlements) and premium amortization	9		( 17 )		10		( 35 )
Net (loss) gain from commodity derivatives	$	( 23 )	$	356	$	140	$	290

We report gains and losses on our commodity derivative c ontracts related to purchases of natural gas in operating expenses on our condensed consolidated statement s of operations as shown in the table below:


	Three months ended September 30,				Nine months ended September 30,
	2025		2024		2025		2024

	(in millions)				(in millions)
Non-cash loss (gain) on natural gas purchase derivatives	$	24	$	( 3 )	$	2	$	( 7 )
Settlements	3		12		22		18
Net loss on natural gas purchase derivatives	$	27	$	9	$	24	$	11

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, 2025 and December 31, 2024.


September 30, 2025
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value

	(in millions)
Other current assets, net	$	87	$	( 10 )	$	77
Other noncurrent assets	33		( 7 )		26

Current liabilities	( 27 )		10		( 17 )
Noncurrent liabilities	( 22 )		7		( 15 )
	$	71	$	—	$	71


December 31, 2024
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value

	(in millions)
Other current assets, net	$	26	$	( 12 )	$	14
Other noncurrent assets	32		( 16 )		16

Current liabilities	( 62 )		12		( 50 )
Noncurrent liabilities	( 61 )		16		( 45 )
	$	( 65 )	$	—	$	( 65 )

NOTE 7 INCOME TAXES

The following table presents the components of our income tax provision (benefit) and effective tax rate:


	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
	(in millions)						(in millions)
Income before income taxes	$	75		$	483		$	479		$	475

Current income tax (benefit) provision	( 24 )			48			52			48
Deferred income tax provision	35			90			76			84
Income tax provision	$	11		$	138		$	128		$	132

Annual effective tax rate	15		%	29		%	27		%	28		%

Our income tax provision for interim periods is determined by applying an estimated annual effective tax rate to income before income taxes with the result adjusted for discrete items, if any, in the relevant period. Our annual effective tax rate for the three months ended September 30, 2025 differed from the U.S. statutory rate of 21% primarily due to state taxes and the marginal well tax credit. For all other periods presented, the difference between the U.S. statutory rate of 21% and our effective tax rate is primarily due to state taxes.

The increase in our deferred tax liability of $ 99 million from $ 113 million as of December 31, 2024 to $ 212 million as of September 30, 2025 is primarily related to finalizing our purchase price allocations related to the Aera Merger and tax law changes. On July 4, 2025, An Act to Provide for Reconciliation Pursuant to Title II of H. Con. Res. 14th, commonly referred to as the One Big Beautiful Bill Act, was signed into law. This law contains several legislative changes including the reinstatement of 100% bonus depreciation under Section 168(k) of the Internal Revenue Code for qualified assets acquired and placed in service after January 19, 2025. This law also reinstated the current expensing of all domestic research and development costs, including favorable transition rules, and restored an EBITDA-based limitation on the amount of annual business interest expense which can be deducted each year under Section 163(j) of the Internal Revenue Code.

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

NOTE 8 DIVESTITURES AND ASSETS HELD FOR SALE

Fort Apache in Huntington Beach

In March 2024, we sold a 0.9 -acre Fort Apache parcel in Huntington Beach, California for $ 10 million and recognized a $ 6 million gain.

Carbon Management Assets

In 2022, we acquired properties for carbon management activities with the intent to divest a portion of these assets. In May 2025, we sold a portion of these properties for $ 1 million. We did not recognize a gain or loss on this transaction.

In September 2025, we reduced the carrying value of these properties classified as held for sale to fair value and recognized an impairment charge of $ 2 million during the three and nine months ended September 30, 2025. The fair value, using Level 3 inputs in the fair value hierarchy, declined due to market conditions.

NOTE 9 SEGMENT INFORMATION

We conduct our business primarily through two reportable segments: (1) oil and natural gas and (2) carbon management. We identified these segments based on the nature of their activities, the types of products sold and services to be provided. Our oil and natural gas segment explores for, develops, and produces oil and condensate, natural gas liquids and natural gas. Our carbon management segment, that we refer to as Carbon TerraVault, is primarily expected to build, install, operate and maintain CO 2 capture equipment, transportation assets and storage facilities. Our oil and natural gas segment and carbon management segment operate exclusively in California.

Revenues related to sales of produced natural gas to our Elk Hills power plant are included in oil, natural gas and natural gas liquids sales in the table below. Direct labor-related costs are allocated to our reportable segments based on job function and activity. General and administrative expenses are allocated to a segment if they directly support a segment's activities. We do not allocate income taxes to our segments. We use proportionate consolidation to account for our share of oil and natural gas producing activities.

The following tables provide segment profit or loss and reconciliations of segment profit or loss to total operating revenues and consolidated income before income taxes for the three and nine months ended September 30, 2025 and 2024.


	Three months ended September 30, 2025
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Elimination		Total

	(in millions)
Oil, natural gas and natural gas liquids sales	$	726	$	—	$	726	$	( 11 )	$	715



Other revenue	2		—		2		—		2

Segment operating revenues	$	728	$	—	$	728


Other revenues and income (a)									138




Total operating revenues									$	855

(a) Other revenues and income includes net gain from commodity derivatives, revenue from marketing of purchased commodities, electricity revenue, interest income and unallocated other revenue.


	Three months ended September 30, 2025
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Reconciliation (Income)/Expense		Total

	(in millions)
Segment operating revenues	$	728	$	—	$	728	$	—	$	728
Less:
Operating costs:
Energy operating costs	97		—		97		( 5 )		92
Gas processing costs	6		—		6		—		6
Non-energy operating costs	218		—		218		—		218
General and administrative expenses	9		4		13		74		87
Depreciation, depletion and amortization	118		—		118		5		123

Taxes other than on income	57		—		57		13		70


Interest expense	—		3		3		22		25
Loss from investment in unconsolidated subsidiaries	—		2		2		—		2


Other segment expenses (a)	41		12		53		—		53
Segment profit or (loss)	$	182	$	( 21 )	$	161




Other profit or loss (b)							( 93 )		( 93 )
Unallocated amounts (c)							70		70








Income before income taxes									$	75

(a) Other segment expenses for our oil and natural gas segment includes transportation costs, accretion expense, and other operating expenses, net. Other segment expenses for our carbon management segment primarily includes operating lease costs and an asset impairment.

(b) Other profit or loss includes the margin we earn from marketing activities and the margin we earn on sales of electricity from our Elk Hills power plant to customers.

(c) Unallocated amounts include net gain from commodity derivatives, net loss on natural gas purchase derivatives, transportation costs, other operating expenses, net, interest income and unallocated other revenue.


	Three months ended September 30, 2024
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Elimination		Total

	(in millions)
Oil, natural gas and NGL sales to external customers	$	878	$	—	$	878	$	( 8 )	$	870



Other revenue	2		—		2		—		2

Segment operating revenues	$	880	$	—	$	880


Other revenues and income (a)									481




Total operating revenues									$	1,353

(a) Other revenue and income includes net gain from commodity derivatives, revenue from marketing of purchased commodities, electricity revenue, interest income and unallocated other revenue.


	Three months ended September 30, 2024
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Reconciliation (Income)/Expense		Total

	(in millions)
Segment operating revenues	$	880	$	—	$	880	$	—	$	880
Less:
Operating costs:
Energy operating costs	97		—		97		( 5 )		92
Gas processing costs	5		—		5		—		5
Non-energy operating costs	214		—		214		—		214
General and administrative expenses	16		5		21		85		106
Depreciation, depletion and amortization	129		—		129		11		140

Taxes other than on income	72		—		72		13		85


Interest expense	—		3		3		26		29
Loss from investment in unconsolidated subsidiary	—		3		3		( 1 )		2


Other segment expenses (a)	49		14		63		—		63
Segment profit or (loss)	$	298	$	( 25 )	$	273




Other profit or loss (b)							( 60 )		( 60 )
Unallocated amounts (c)							( 279 )		( 279 )








Income before income taxes									$	483

(a) Amounts for our oil and natural gas segment include transportation costs, accretion expense, asset impairment, and other operating expenses, net. Amounts for our carbon management segment primarily include operating lease costs.

(b) Other profit or loss includes margin from purchased commodities and the margin we earn on sales of electricity from our Elk Hills power plant to customers.

(c) Unallocated amounts include net gain from commodity derivatives, transportation costs, other operating expenses, net, other non-operating loss, interest income, unallocated other revenue and loss on early extinguishment of debt.


	Nine months ended September 30, 2025
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Elimination		Total

	(in millions)
Oil, natural gas and natural gas liquids sales	$	2,265	$	—	$	2,265	$	( 34 )	$	2,231



Other revenue	7		—		7		—		7

Segment operating revenues	$	2,272	$	—	$	2,272


Other revenues and income (a)									507




Total operating revenues									$	2,745

(a) Other revenues and income includes net gain from commodity derivatives, revenue from marketing of purchased commodities, electricity revenue, interest income and unallocated other revenue.


	Nine months ended September 30, 2025
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Reconciliation (Income)/Expense		Total

	(in millions)
Segment operating revenues	$	2,272	$	—	$	2,272	$	—	$	2,272
Less:
Operating costs:
Energy operating costs	293		—		293		( 20 )		273
Gas processing costs	15		—		15		—		15
Non-energy operating costs	639		—		639		—		639
General and administrative expenses	30		10		40		198		238
Depreciation, depletion and amortization	365		—		365		17		382

Taxes other than on income	157		—		157		30		187


Interest expense	—		8		8		69		77
Loss from investment in unconsolidated subsidiaries	—		4		4		( 1 )		3


Other segment expenses (a)	131		44		175		—		175
Segment profit or (loss)	$	642	$	( 66 )	$	576




Other profit or loss (b)							( 164 )		( 164 )
Unallocated amounts (c)							( 32 )		( 32 )








Income before income taxes									$	479

(b) Other profit or loss includes the margin we earn from marketing activities and the margin we earn on sales of electricity from our Elk Hills power plant to customers.

(c) Unallocated amounts include net gain from commodity derivatives, net loss on natural gas purchase derivatives, transportation costs, other operating expenses, net, other non-operating losses, loss on early extinguishment of debt, interest income and unallocated other revenue.


	Nine months ended September 30, 2024
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Elimination		Total

	(in millions)
Oil, natural gas and NGL sales to external customers	$	1,729	$	—	$	1,729	$	( 18 )	$	1,711



Other revenue	5		—		5		—		5

Segment operating revenues	$	1,734	$	—	$	1,734


Other revenues and income (a)									605




Total operating revenues									$	2,321

(a) Other revenue and income includes net gain from commodity derivatives, revenue from marketing of purchased commodities, electricity revenue, interest income and unallocated other revenue.


	Nine months ended September 30, 2024
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Reconciliation (Income)/Expense		Total

	(in millions)
Segment operating revenues	$	1,734	$	—	$	1,734	$	—	$	1,734
Less:
Operating costs:
Energy operating costs	197		—		197		( 11 )		186
Gas processing costs	12		—		12		—		12
Non-energy operating costs	445		—		445		—		445
General and administrative expenses	34		10		44		182		226
Depreciation, depletion and amortization	225		—		225		21		246

Taxes other than on income	137		—		137		25		162


Interest expense	—		6		6		53		59
Loss from investment in unconsolidated subsidiary	—		10		10		( 1 )		9


Other segment expenses (a)	137		37		174		—		174
Segment profit or (loss)	$	547	$	( 63 )	$	484




Other profit or loss (b)							( 107 )		( 107 )
Unallocated amounts (c)							( 153 )		( 153 )








Income before income taxes									$	475

(a) Amounts for our oil and natural gas segment include transportation costs, accretion expense, asset impairment and other operating expenses, net. Amounts for our carbon management segment primarily include operating lease costs.

(b) Other profit or loss includes margin from purchased commodities and the margin we earn on sales of electricity from our Elk Hills power plant to customers.

The following table provides capital investment by segment and a reconciliation to our consolidated capital investment for the three and nine months ended September 30, 2025 and 2024. We do not provide total assets by segment because it is not used by our Chief Operating Decision Maker. See Note 3 Investments and Related Party Transactions for information on our investment in the Carbon TerraVault JV, which is part of our carbon management segment.


	Oil and Natural Gas		Carbon Management		Corporate and Other		Total

	(in millions)
Three months ended September 30, 2025	$	72	$	15	$	4	$	91
Three months ended September 30, 2024	$	74	$	4	$	1	$	79


	Oil and Natural Gas		Carbon Management		Corporate and Other		Total

	(in millions)
Nine months ended September 30, 2025	$	165	$	22	$	15	$	202
Nine months ended September 30, 2024	$	156	$	6	$	5	$	167

NOTE 10 STOCKHOLDERS' EQUITY

Share Repurchase Program

Our Board of Directors authorized a Share Repurchase Program to acquire up to $ 1.35 billion of our common stock through June 30, 2026. The total value of shares that may yet be purchased under the Share Repurchase Program totaled $ 205 million as of September 30, 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.

Pursuant to our Share Repurchase Program, we repurchased 7,787,969 shares of common stock during the nine months ended September 30, 2025. For the nine months ended September 30, 2025, the aggregate purchase price consideration, inclusive of excise taxes, for our shares was $ 354 million. We funded our share repurchases with available cash.

The following table summarizes our share repurchases, for the periods presented. There were no repurchases during the three months ended September 30, 2025; however we remitted $ 34 million in U.S. federal taxes withheld from a June 2025 share repurchase.


	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, 2024	835,319	$	42	$	50.23


Nine months ended September 30, 2024	2,604,922	$	135	$	51.33
Nine months ended September 30, 2025	7,787,969	$	354	$	45.23

Note: The total value of shares purchased includes accrued excise taxes, which are generally paid in the year following the share repurchase. Commissions paid on share repurchases were not significant in all periods presented.

Dividends

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


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

2025
Three months ended March 31, 2025	$	35	$	0.3875




Three months ended June 30, 2025	35		$	0.3875
Three months ended September 30, 2025	32		$	0.3875
Nine months ended September 30, 2025	$	102
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

In addition to dividends on our common stock shown in the table above, we paid $ 1 million of dividend equivalents on equity-settled stock-based compensation awards in the nine months ended September 30, 2025 and $ 4 million of dividend equivalents 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 16 Subsequent Events for information on future cash dividends.

NOTE 11 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) were calculated using the treasury stock method for the three and nine months ended September 30, 2025 and 2024. 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, 2025 and 2024:


	Three months ended September 30,				Nine months ended September 30,
	2025		2024		2025		2024

	(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS
Net income	$	64	$	345	$	351	$	343





Denominator for Basic EPS
Weighted-average shares	83.7		89.4		87.8		75.5

Potential common shares, if dilutive:
Warrants	—		1.0		—		1.1
Restricted stock units	0.4		0.4		0.3		0.5
Performance stock units	0.3		0.4		0.3		0.5

Denominator for Diluted EPS
Weighted-average shares	84.4		91.2		88.4		77.6

EPS
Basic	$	0.76	$	3.86	$	4.00	$	4.54
Diluted	$	0.76	$	3.78	$	3.97	$	4.42

NOTE 12 PENSION AND POSTRETIREMENT BENEFIT PLANS

The following table sets forth the components of the net periodic benefit costs for our defined benefit pension and postretirement benefit plans for the three and nine months ended September 30, 2025 and 2024:



	Three months ended September 30,				Three months ended September 30,
	2025				2024
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit

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


Cost of special termination benefits	—		—		—		4

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



	Nine months ended September 30,				Nine months ended September 30,
	2025				2024
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit

	(in millions)				(in millions)
Service cost - benefits earned during the period	$	1	$	2	$	3	$	2
Interest cost on projected benefit obligation	11		4		4		2
Expected return on plan assets	( 17 )		( 3 )		( 7 )		( 1 )
Curtailment gain	—		—		—		( 4 )

Settlement loss	1		—		—		—
Cost of special termination benefits	—		—		—		4
Amortization of net actuarial gain	—		( 1 )		—		( 1 )
Amortization of prior service cost credit	—		( 4 )		—		( 4 )
Net periodic benefit costs	$	( 4 )	$	( 2 )	$	—	$	( 2 )

Contributions to our pension benefit plans were insignificant during the three and nine months ended September 30, 2025. Contributions were insignificant during the three months ended September 30, 2024 and we contributed $ 2 million to our pension benefit plans during the nine months ended September 30, 2024 . We do not expect to need to make any contributions to our qualified pension plans to satisfy minimum funding requirements during the remainder of 2025 . We expect to contribute an insignificant amount to fund our pension benefit distributions during the remainder of 2025 .

NOTE 13 SUPPLEMENTAL ACCOUNT BALANCES

Restricted cash — Cash and cash equivalents includes restricted cash of $ 16 million and $ 18 million at September 30, 2025 and December 31, 2024, respectively. Restricted cash 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.

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



	Three months ended September 30,				Nine months ended September 30,
	2025		2024		2025		2024

	(in millions)				(in millions)
Oil	$	653	$	804	$	2,033	$	1,505
Natural gas	26		22		73		68
Natural gas liquids	36		44		125		138
Oil, natural gas and natural gas liquids sales	$	715	$	870	$	2,231	$	1,711

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,
	2025		2024		2025		2024


	(in millions)				(in millions)
Oil	$	20	$	25	$	66	$	73
Natural gas	38		26		106		97
Natural gas liquids	—		—		6		6
Revenue from marketing of purchased commodities	$	58	$	51	$	178	$	176

Inventory — Materials and supplies, which primarily consist of well equipment and tubular goods used in our oil and natural gas operations and critical spares related to our cogeneration power plants, are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods include produced oil and natural gas liquids in storage, which are valued at the lower of cost or net realizable value. Inventory, by category, is as follows:


	September 30,		December 31,
	2025		2024

	(in millions)
Materials and supplies	$	89	$	86
Finished goods	5		4
Inventory	$	94	$	90

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


	September 30,		December 31,
	2025		2024

	(in millions)
Net amounts due from joint interest partners (a)	$	40	$	41

Fair value of commodity derivative contracts	77		14
Prepaid expenses	17		28
Greenhouse gas allowances	2		27

Income tax receivable	51		50

Other	16		16
Other current assets, net	$	203	$	176

(a) The amounts due from joint interest partners include insignificant amounts of allowances for credit losses for each period presented.

Other noncurrent assets — Other noncurrent assets include the following:



	September 30,		December 31,
	2025		2024

	(in millions)
Operating lease right-of-use assets	$	95	$	105
Deferred financing costs - Revolving Credit Facility	21		23
Emission reduction credits	11		11

Fair value of commodity derivative contracts	26		16
Funded pension	73		67
Postretirement plan	14		13
Other	40		37
Other noncurrent assets	$	280	$	272

Accrued liabilities — Accrued liabilities include the following:


	September 30,		December 31,
	2025		2024

	(in millions)
Compensation-related liabilities	$	101	$	177

Taxes other than on income	95		100
Asset retirement obligations - current portion	135		134

Operating lease liability	22		15
Fair value of derivative contracts	17		50
Premiums due on commodity derivative contracts	19		14



Advanced payments	14		25


Payable to the former owners of Aera	9		29
Other	67		67
Accrued liabilities	$	479	$	611

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



	September 30,		December 31,
	2025		2024

	(in millions)
Compensation-related liabilities	$	46	$	50
Postretirement and pension benefit plans	56		59
Operating lease liability	67		76
Fair value of commodity derivative contracts	15		45

Contingent liability ( Note 3 Investments and Related Party Transactions )	115		107
Other	26		40
Other long-term liabilities	$	325	$	377

NOTE 14 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,
	2025		2024		2025		2024

	(in millions)				(in millions)
Supplemental cash flow information
Interest paid, net of amounts capitalized	$	2	$	23	$	47	$	42
Income taxes paid	$	6	$	29	$	45	$	55
Interest income	$	1	$	1	$	6	$	15

Supplemental disclosure of non-cash investing and financing activities
Contributions to the Carbon TerraVault JV	$	11	$	15	$	26	$	20
Issuance of shares for stock-based compensation awards	$	2	$	—	$	23	$	88
Dividend equivalents for stock-based compensation awards	$	1	$	2	$	2	$	2
Excise tax on share repurchases	$	—	$	—	$	2	$	1

NOTE 15 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 the indenture governing our 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, 2025 and December 31, 2024 and the condensed consolidating statements of operations for the three and nine months ended September 30, 2025 and 2024, 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, 2025 and December 31, 2024


	As of September 30, 2025
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total current assets	$	260	$	27	$	525	$	—	$	812
Total property, plant and equipment, net	23		52		5,455		—		5,530
Investments in consolidated subsidiaries	5,706		( 46 )		17,013		( 22,673 )		—
Deferred tax asset	27		—		—		—		27
Investment in unconsolidated subsidiaries	—		49		53		—		102
Other assets	117		45		118		—		280
TOTAL ASSETS	$	6,133	$	127	$	23,164	$	( 22,673 )	$	6,751

Total current liabilities	269		19		629		—		917
Long-term debt	889		—		—		—		889
Asset retirement obligations	—		—		965		—		965
Other long-term liabilities	106		133		86		—		325
Deferred tax liability	212		—		—		—		212
Amounts due to (from) affiliates	1,214		72		( 1,286 )		—		—
Total equity	3,443		( 97 )		22,770		( 22,673 )		3,443
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	6,133	$	127	$	23,164	$	( 22,673 )	$	6,751


	As of December 31, 2024
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total current assets	$	437	$	46	$	541	$	—	$	1,024
Total property, plant and equipment, net	14		31		5,635		—		5,680
Investments in consolidated subsidiaries	4,869		( 32 )		15,050		( 19,887 )		—
Deferred tax asset	73		—		—		—		73
Investment in unconsolidated subsidiary	—		27		59		—		86
Other assets	113		58		101		—		272
TOTAL ASSETS	$	5,506	$	130	$	21,386	$	( 19,887 )	$	7,135

Total current liabilities	224		14		742		—		980
Long-term debt	1,132		—		—		—		1,132
Asset retirement obligations	—		—		995		—		995
Other long-term liabilities	114		138		125		—		377
Amounts due to (from) affiliates	385		—		( 385 )		—		—
Deferred tax liability	113		—		—		—		113
Total equity	3,538		( 22 )		19,909		( 19,887 )		3,538
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	5,506	$	130	$	21,386	$	( 19,887 )	$	7,135

Condensed Consolidating Statement of Operations

For the three and nine months ended September 30, 2025 and 2024


	Three months ended September 30, 2025
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total operating revenues	$	1	$	—	$	875	$	( 21 )	$	855
Total costs and other	90		13		672		( 19 )		756
Loss on asset divestitures	—		—		( 1 )		—		( 1 )
Non-operating (loss) income	( 22 )		( 4 )		3		—		( 23 )
(LOSS) INCOME BEFORE INCOME TAXES	( 111 )		( 17 )		205		( 2 )		75
Income tax provision	( 11 )		—		—		—		( 11 )
NET (LOSS) INCOME	$	( 122 )	$	( 17 )	$	205	$	( 2 )	$	64


	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


	Nine months ended September 30, 2025
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total operating revenues	$	6	$	—	$	2,800	$	( 61 )	$	2,745
Total costs and other	265		47		1,940		( 59 )		2,193
Loss on asset divestitures	—		—		( 1 )		—		( 1 )
Non-operating (loss) income	( 70 )		( 11 )		9		—		( 72 )
(LOSS) INCOME BEFORE INCOME TAXES	( 329 )		( 58 )		868		( 2 )		479
Income tax provision	( 128 )		—		—		—		( 128 )
NET (LOSS) INCOME	$	( 457 )	$	( 58 )	$	868	$	( 2 )	$	351


	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

NOTE 16 SUBSEQUENT EVENTS

2034 Senior Notes

On October 8, 2025, we completed a private offering of $ 400 million in an aggregate principal amount of 7.000 % senior notes due 2034 (2034 Senior Notes). The terms of the 2034 Senior Notes are governed by the Indenture, dated as of October 8, 2025, by and among us, the guarantors and Wilmington Trust, National Association, as trustee (2034 Senior Notes Indenture). The 2034 Senior Notes will mature on January 15, 2034. Our 2034 Senior Notes are subject to a special mandatory redemption in certain circumstances if the Berry Merger does not close prior to March 14, 2026 (subject to up to two three -month extensions by either us or Berry upon written notice in certain circumstances). As of September 30, 2025, it was not probable that this redemption feature would be triggered.

Security – Our 2034 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 2029 Senior Notes.

Redemption – We may redeem the 2034 Senior Notes at any time on or after January 15, 2029 at the redemption prices of (i) 103.500 % during the twelve-month period beginning on January 15, 2029, (ii) 101.750 % during the twelve-month period beginning on January 15, 2030 and (iii) 100.000 % after January 15, 2031 and before the maturity date. Prior to January 15, 2029, we may on one or more occasions redeem up to 40 % of the aggregate principal amount of the 2034 Senior Notes with an amount not greater than the net cash proceeds of one or more equity offerings at the redemption price of 107.000 % provided that (i) at least 60 % of the aggregate principal amount of the 2034 Senior Notes originally issued remains outstanding immediately after the redemption and (ii) the redemption occurs within 180 days of the date of the closing of the equity offering.

In addition, before January 15, 2029, we may redeem some or all of the 2034 Senior Notes at a redemption price equal to 100 % of the aggregate principal amount of the 2034 Senior Notes redeemed, plus the applicable premium as specified in the 2034 Senior Notes Indenture and accrued and unpaid interest, if any, to, but excluding, the redemption date.

Other Covenants – Our 2034 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 2034 Senior Notes provide for certain triggering events, including upon a change of control, as defined in the 2034 Senior Notes Indenture, that would require us to repurchase all or any part of the 2034 Senior Notes at a price equal to 101 % of the aggregate principal amount plus accrued and unpaid interest.

2026 Senior Notes Redemption

In October 2025, we redeemed $ 122 million of our 2026 Senior Notes at 100 % of the principal amount, resulting in an insignificant extinguishment loss for the write-off of unamortized debt issuance costs. Following this redemption, none of our 2026 Senior Notes were outstanding.

Seventh Amendment to Revolving Credit Facility

In October 2025, we entered into a seventh amendment to our Revolving Credit Facility to, among other things, (i) add certain new lenders to the facility, and (ii) increase the aggregate elected commitment amount of the lenders from $ 1.15 billion to $ 1.45 billion.

Dividend

On November 4, 2025 , our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of $ 1.62 , payable to shareholders in quarterly increments of $ 0.405 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 4, 2025 , our Board of Directors declared a quarterly cash dividend of $ 0.405 per share of common stock. The dividend is payable to shareholders of record at the close of business on December 1, 2025 and is expected to be paid on December 15, 2025 .

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

General

Pending Berry Merger

On September 14, 2025, we entered into a definitive agreement and plan of merger (the Berry Merger Agreement) to combine with Berry Corporation (Berry) in an all-stock transaction (Berry Merger). Berry is an independent upstream energy company that operates in two business segments: (i) oil and natural gas and (ii) well servicing and abandonment services. Berry's oil and gas assets are located in California and Utah. We expect the transaction will add high quality, oil-weighted, mostly conventional proved developed reserves and sustainable cash flows to our operations.

Pursuant to the Berry Merger Agreement, on the effective date of the merger, we will issue 0.0718 shares of our common stock for each outstanding share of Berry stock. Upon completion of the Berry Merger, we expect our existing stockholders to own approximately 94% of the combined company upon closing.

We expect Berry's outstanding long-term debt to be repaid and the underlying credit agreement to be terminated at closing. We expect to repay a significant portion of this indebtedness with proceeds from our 2034 Senior Notes, which closed in October 2025. Berry's Revolving Credit Facility is also expected to be terminated at closing. For more information on the 2034 Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 16 Subsequent Events .

Business Environment and Industry Outlook

Commodity Prices

Our operating results, and those of the oil and natural gas industry, are heavily influenced by commodity prices. Oil and natural gas prices and differentials can fluctuate significantly due to various market-related factors, making it challenging to predict realized prices reliably. We may respond to changing economic conditions by adjusting the amount and allocation of our capital program or by pursuing additional efficiencies and cost savings. Prolonged volatility in oil and natural gas prices may also affect the quantities of reserves that we can economically produce over the longer term. Refer to Results of Our Oil and Natural Gas Operations, Production, Prices and Realizations below for information on our realized prices.

During 2025, oil prices experienced volatility driven by global supply and demand factors, including a series of announcements by OPEC+ indicating its intention to return offline production to the market more quickly than previously anticipated, and by concerns over global trade following multiple tariff announcements.

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,		June 30,		September 30,		September 30,
	2025		2025		2025		2024
Brent oil ($/Bbl)	$	68.13	$	66.76	$	69.94	$	81.79
WTI oil ($/Bbl)	$	64.93	$	63.74	$	66.70	$	77.54
NYMEX Henry Hub ($/MMBtu)	$	3.07	$	3.44	$	3.39	$	2.10

Supply Chain and Inflation

We continued to experience relatively flat pricing from our suppliers during the first nine months of 2025 compared to the prior year. U.S. tariff policy regarding both country of origin and material type remains highly uncertain and subject to future changes. The United States recently expanded tariff rates on imported goods including a 50% tariff on the steel and aluminum value of imported products. If sustained, these expanded tariff rates could increase our cost of oilfield goods and extend delivery lead times over the longer term. We have taken measures to limit the effects of potential price increases caused by the recent expansion of U.S. tariffs by entering into fixed price contracts with terms of one to three years for a significant majority of our materials and services based on our current expected development plans. We also pre-purchased inventory prior to the implementation of the tariffs and continue to purchase from vendors who source domestic content to limit the impact of foreign tariffs on our business. Overall, we expect minimal impact from tariffs on our supply chain in 2025. However, if the current tariff regime persists or expands, our inventory, capital and operating costs could increase over the long-term.

Marketing Arrangements

In October 2025, Phillips 66 closed its Wilmington refinery in Los Angeles, California. In April 2025, Valero notified the California Energy Commission of its intent to idle, restructure, or cease refining operations at its Benicia refinery in the San Francisco Bay Area by the end of April 2026. Although Valero has stated that it is in ongoing discussion with the California government, it recently confirmed plans to cease refining operations at Benicia and presently does not expect any changes to the previously announced timeline. We have historically sold a portion of our crude oil to these refineries.

Following the closure of the Phillips 66 refinery, and assuming Valero's Benicia refinery ceases operations, six major petroleum refineries would remain in California, each with a refining capacity exceeding 75,000 barrels per day. Five of these refineries currently purchase California crude oil. If Valero's Benicia refinery ceases operations, California would have approximately 1.1 million barrels per day of refining capacity available to process California crude oil, which is approximately four times the volume of crude oil produced in the state in 2024.

Given this available refining capacity and the flexibility we have in marketing our crude oil production, we do not currently expect the cessation of operations at these refineries, should the Valero Benicia refinery cease operations, to have a material impact on our ability to market our crude oil. While these announcements have not affected our price realizations to date, a reduction in the number of refineries operating in California has the potential to impact our future price realizations.

Regulatory Updates

Recent Legislation

Senate Bill 237 (Oil and Gas Permitting)

Senate Bill 237 (SB 237) was enacted in September 2025 and implements a number of changes to help facilitate new and continued oil and gas production in California (particularly in Kern County). Among other provisions, SB 237 deems a specified Kern County environmental impact report sufficient for full compliance with the requirements of the California Environmental Quality Act (CEQA) for purposes of a certain County of Kern zoning ordinance related to oil and gas activities and requires no further environmental review. These provisions of SB 237 will become effective as of January 1, 2026. We expect Kern County and the California Geologic Energy Management Division to resume issuing new well permits in Kern County in 2026 up to the maximum allowable amount of 2,000 new drill wells per year for up to ten years.

We believe that this legislation provides greater regulatory certainty for oil and gas operations in Kern County, which accounts for a substantial portion of California’s crude oil and natural gas production. The adoption of SB 237 is particularly important to our business as we are the largest producer of oil and gas in Kern County and the majority of our production and reserves are located there. By facilitating the timely resumption of permitting activity, we expect that this legislation will support operational continuity and investment planning by California’s oil and gas industry. In addition, we believe that the increased clarity around permitting standards will help to enhance long-term development opportunities in Kern County, benefiting both the broader industry and CRC’s asset base in the region.

Assembly Bill 1207 (Cap-and-Invest Extension)

Assembly Bill 1207 (AB 1207) was enacted in September 2025. AB 1207 primarily extends California’s greenhouse-gas Cap-and-Invest program through 2045, providing long-term policy certainty for covered entities under the Program. AB 1207 establishes emission reduction initiatives and enhances program transparency through expanded reporting requirements for the California Air Resources Board. The legislation also establishes a Climate Mitigation Fund to support consumer rebates and investments to reduce household energy costs.

Senate Bill 614 (Carbon Dioxide Pipeline Regulation)

Senate Bill 614 (SB 614), enacted in October 2025, revises the definition of “pipeline” for purposes of the Elder California Pipeline Safety Act of 1981 to include intrastate pipelines used for the transportation of carbon dioxide (CO₂). The law requires the Office of the State Fire Marshal to, by July 1, 2026, adopt implementing regulations regarding the safe transportation of CO₂ in pipelines, after which the current moratorium on CO₂ pipeline operations may be lifted. The legislation mandates stringent design, routing, and disclosure standards consistent with or exceeding federal requirements under the Pipeline and Hazardous Materials Safety Administration. Upon implementation, SB 614 is expected to enable the development of carbon-capture and storage infrastructure in California while imposing additional permitting, safety, and compliance obligations on operators of CO₂ transportation systems.

Well Permitting

During the three months ended September 30, 2025, we received well permits for 140 workovers and 89 sidetracks. During the nine months ended September 30, 2025, we have received total well permits for 279 workovers, 194 sidetracks and 5 deepenings.

We have not received any permits for new oil and gas wells in 2025. We believe that the enactment of SB 237 will ultimately result in CalGEM issuing new well permits beginning in 2026, and expect the rate of workover and sidetrack permit approvals to also increase throughout 2026.

We currently hold sufficient permits to exit the year with a four drilling rig capital program. Our ability to maintain a four drilling rig program throughout 2026 will require us to obtain new permits which we expect to become available in 2026 following the enactment of SB 237. See Liquidity and Capital Resources, Capital Program for more information.

For further information regarding well permitting, see Part I, Items 1 & 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities, Well Permitting in our 2024 Annual Report.

Kern County EIR Litigation

The Trial Court may act in the Kern County litigation matter later this year, although timing is uncertain. The enactment of SB 237 does not result in an immediate dismissal of the pending litigation, although it will provide support for dismissal of this litigation if it is still pending when the law becomes effective in January 2026. Developments in this litigation or in the permitting process more broadly that are adverse to Kern County could further adversely affect our business, results of operations and financial condition.

Statements of Operations Analysis

Our consolidated results of operations include the results of Aera beginning on 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 Business Combinations . The Aera Merger affected the comparability of our financial results for the nine months ended September 30, 2025 to the prior comparative period.

Consolidated Results of Operations

Three months ended September 30, 2025 compared to June 30, 2025

The following table presents our consolidated operating revenues for the periods indicated:


	Three months ended
	September 30, 2025		June 30, 2025

	(in millions)
Oil, natural gas and natural gas liquids sales	$	715	$	702
Net (loss) gain from commodity derivatives	(23)		157
Revenue from marketing of purchased commodities	58		56
Electricity revenue	101		58
Other revenue	4		5
Total operating revenues	$	855	$	978

Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $715 million for the three months ended September 30, 2025, which is an increase of $14 million compared to $702 million for the three months ended June 30, 2025.

The following table shows changes in oil, natural gas and natural gas liquids sales for the three months ended September 30, 2025 compared to the three months ended June 30, 2025:


	Oil		NGLs		Natural Gas		Total Operations

	(in millions)
Three months ended June 30, 2025	$	644	$	39	$	19	$	702
Changes in realized prices	12		(1)		7		18
Changes in production and other	(3)		(2)		3		(2)
Changes in intersegment revenues	—		—		(3)		(3)

Three months ended September 30, 2025	$	653	$	36	$	26	$	715

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

Net (loss) gain from commodity derivatives — We report gains and losses on our derivative contracts related to sales of our oil and marketing activities in operating revenues. Net loss from commodity derivatives was $23 million for the three months ended September 30, 2025 compared to a net gain of $157 million for the three months ended June 30, 2025. The change primarily resulted from the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:


	Three months ended
	September 30, 2025		June 30, 2025
	(in millions)
Non-cash commodity derivative (loss) gain	$	(32)	$	140
Net proceeds and premium amortization	9		17
Net (loss) gain from commodity derivatives	$	(23)	$	157

Electricity revenue — Electricity revenue increased by $43 million to $101 million for the three months ended September 30, 2025 compared to $58 million for the three months ended June 30, 2025. This increase was primarily a result of higher resource adequacy revenues during the three months ended September 30, 2025 compared to the three months ended June 30, 2025.

The following table presents our consolidated operating and non-operating expenses and income for the three months ended September 30, 2025 and June 30, 2025.


	Three months ended
	September 30, 2025		June 30, 2025

	(in millions)
Operating expenses
Operating costs	$	316	$	295
General and administrative expenses	87		79
Depreciation, depletion and amortization	123		128
Asset impairment	2		—
Taxes other than on income	70		47

Costs related to marketing of purchased commodities	44		41
Electricity generation expenses	11		5
Transportation costs	19		20
Accretion expense	28		28
Net loss on natural gas purchase derivatives	27		3


Other operating expenses, net	29		65
Total operating expenses	756		711
Loss on asset divestitures	(1)		—
Operating income	98		267

Non-operating (expenses) income

Interest and debt expense, net	(25)		(25)

Loss from investment in unconsolidated subsidiaries	(2)		—
Other non-operating income, net	4		—
Income before income taxes	75		242
Income tax provision	(11)		(70)
Net income	$	64	$	172

Operating costs — The following table presents our operating costs for the three months ended September 30, 2025 and June 30, 2025:


	Three months ended
	September 30, 2025		June 30, 2025

	(in millions)

Energy operating costs	$	92	$	78
Gas processing costs	6		5
Non-energy operating costs	218		212
Operating costs	$	316	$	295

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 produce electricity used in our operations. These internal costs include an allocation of the direct costs to produce electricity at our Elk Hills power plant based on electricity consumption by our Elk Hills and nearby fields. We do not allocate the costs to produce steam at our Elk Hills power plant which is then used in oil and natural gas 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.

Energy operating costs — Energy operating costs for the three months ended September 30, 2025 were $92 million, which was an increase of $14 million from $78 million for the three months ended June 30, 2025. This increase was primarily due to higher prices for electricity and natural gas used in our steamflood operations.

Taxes other than on income — Taxes other than on income for the three months ended September 30, 2025 were $70 million, which was an increase of $23 million from $47 million for the three months ended June 30, 2025. The three months ended June 30, 2025, included a downward adjustment to our estimated annual production tax rate. Greenhouse gas expense increased for the three months ended September 30, 2025 due to running the Elk Hills power plant at a higher operational capacity and market prices for purchased allowances were higher than prevailing market prices during the three months ended June 30, 2025.

Net loss on natural gas purchase derivatives — Net loss from derivatives related to our purchase of natural gas was $27 million for the three months ended September 30, 2025 compared to a net loss of $3 million for the three months ended June 30, 2025. The change 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. Gains and losses from our commodity derivative contracts are shown in the table below:


	Three months ended
	September 30, 2025		June 30, 2025
	(in millions)
Non-cash loss (gain) on natural gas purchase derivatives	$	24	$	(4)
Settlements	3		7
Net loss on natural gas purchase derivatives	$	27	$	3

Other operating expenses, net — Other operating expenses, net decreased $36 million to $29 million for the three months ended September 30, 2025 compared to $65 million for the three months ended June 30, 2025. For the three months ended September 30, 2025 and June 30, 2025, other operating expenses, net includes the following:


	Three months ended
	September 30, 2025		June 30, 2025
	(in millions)
Carbon management expenses	$	10	$	14
Transaction and integration costs	6		3
Severance	—		6
Signal Hill decommissioning expense	5		2
Litigation and settlement related expenses (a)	1		25
All other	7		15
Total operating expenses, net	$	29	$	65

(a) See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for more information on a $25 million payment we made to CalGEM during the three months ended June 30, 2025.

Income taxes – The income tax provision for the three months ended September 30, 2025 was $11 million (representing an effective tax rate of 15%), compared to a provision of $70 million (representing an effective tax rate of 29%) for the three months ended June 30, 2025. The effective tax rate for the three months ended September 30, 2025, reflects the benefit related to guidance published for the marginal well tax credit. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes .

Nine months ended September 30, 2025 compared to September 30, 2024

The following table presents our consolidated operating revenues for the periods indicated:


	Nine months ended
	September 30, 2025		September 30, 2024

	(in millions)
Oil, natural gas and natural gas liquids sales	$	2,231	$	1,711
Net gain from commodity derivatives	140		290
Revenue from marketing of purchased commodities	178		176
Electricity revenue	181		120
Other revenue	15		24
Total operating revenues	$	2,745	$	2,321

Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $2,231 million for the nine months ended September 30, 2025, which is an increase of $520 million compared to $1,711 million for the nine months ended September 30, 2024.

The following table shows changes in oil, natural gas and natural gas liquids sales for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024.


	Oil		NGLs		Natural Gas		Total Operations

	(in millions)
Nine months ended September 30, 2024	$	1,505	$	138	$	68	$	1,711
Changes in realized prices	(206)		(5)		22		(189)
Changes in production and other (a)	734		(8)		1		727
Changes in intersegment revenues	—		—		(18)		(18)

Nine months ended September 30, 2025	$	2,033	$	125	$	73	$	2,231

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

(a) The increase in production primarily relates to the addition of the Aera fields on July 1, 2024. See Part I, Item 1 – Financial Statements, Note 2 Business Combinations for additional information.

Net gain from commodity derivatives – We report gains and losses on our derivative contracts related to sales of our produced oil and marketing activities in operating revenue. Net gain from commodity derivatives was $140 million for the nine months ended September 30, 2025 compared to a net gain of $290 million for the nine months ended September 30, 2024. The change primarily resulted from payments to settle commodity derivative contracts and the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:


	Nine months ended
	September 30, 2025		September 30, 2024

	(in millions)
Non-cash commodity derivative gain	$	130	$	325
Net proceeds (settlements) and premium amortization	10		(35)
Net gain from commodity derivatives	$	140	$	290

Electricity revenue — Electricity revenue increased by $61 million to $181 million for the nine months ended September 30, 2025 compared to $120 million for the nine months ended September 30, 2024. This increase was primarily a result of higher pricing from resource adequacy contracts. Additionally, we experienced lower revenues during the nine months ended September 30, 2024 as a result of downtime at our Elk Hills power plant.

The following table presents our consolidated operating and non-operating expenses and income for the nine months ended September 30, 2025 and September 30, 2024.


	Nine months ended
	September 30, 2025		September 30, 2024

	(in millions)
Operating expenses
Operating costs	$	927	$	643
General and administrative expenses	238		226
Depreciation, depletion and amortization	382		246
Asset impairment	2		13
Taxes other than on income	187		162

Costs related to marketing of purchased commodities	135		140
Electricity generation expenses	26		31
Transportation costs	59		60
Accretion expense	85		56
Net loss on natural gas purchase derivatives	24		11

Measurement period adjustments, net	1		—
Other operating expenses, net	127		188
Total operating expenses	2,193		1,776
(Loss) gain on asset divestitures	(1)		7
Operating income	551		552

Non-operating (expenses) income

Interest and debt expense, net	(77)		(59)
Loss on early extinguishment of debt	(1)		(5)
Loss from investment in unconsolidated subsidiaries	(3)		(9)
Other non-operating income (expenses), net	9		(4)
Income before income taxes	479		475
Income tax provision	(128)		(132)
Net income	$	351	$	343

Operating costs — The following table presents our operating costs for the nine months ended September 30, 2025 and September 30, 2024.


	Nine months ended
	September 30, 2025		September 30, 2024

	(in millions)
Energy operating costs	$	273	$	186
Gas processing costs	15		12
Non-energy operating costs	639		445
Operating costs	$	927	$	643

Energy operating costs — Energy operating costs for the nine months ended September 30, 2025 were $273 million , which was an increase of $87 million from $186 million for the nine months ended September 30, 2024. The increase is primarily related to the addition of the Aera fields for the full nine months of 2025 compared to the same prior year period. Excluding the Aera fields, our energy operating costs for the nine months ended September 30, 2025 decreased primarily due to the additional supply of electricity generated at our Elk Hills power plant which is used at our Elk Hills field. During the nine months ended September 30, 2024, our Elk Hills power plant experienced unplanned downtime and scheduled maintenance.

Non-energy operating costs — Non-energy operating costs for the nine months ended September 30, 2025 were $639 million , which was an increase of $194 million from $445 million for the nine months ended September 30, 2024. The increase is primarily related to the operation of the Aera fields for the full nine months of 2025 compared to a three-month period in the same prior year period. We also had higher surface maintenance activity during the nine months ended September 30, 2025 compared to the same prior year period.

General and administrative expenses — General and administrative (G&A) expenses were $238 million for the nine months ended September 30, 2025 compared to $226 million for the nine months ended September 30, 2024, which was an increas e of $12 million. The increase was primarily due to additional compensation-related expense and other corporate expenses resulting from the Aera Merger.

Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) for the nine months ended September 30, 2025 was $382 million compared to $246 million durin g the nine months ended September 30, 2024. The increase of $136 million was primarily the result of the addition of the Aera assets included in the nine months ended September 30, 2025. See Part I, Item 1 – Financial Statements, Note 2 Business Combinations for information on the Aera assets.

Asset impairments — During the nine months ended September 30, 2024, we recognized a $13 million impairment for excess and obsolete materials and supplies related to our oilfield operations. We recognized a $2 million asset impairment during the nine months ended September 30, 2025 related to a fair value adjustment for properties held for sale. See Part I, Item 1 – Financial Statements, Note 8 Divestitures and Acquisitions for additional information on the impairment.

Taxes other than on income — Taxes other than on income for the nine months ended September 30, 2025 were $187 million, which is an increase of $25 million from $162 million for the nine months ended September 30, 2024. This increase was a result of higher greenhouse gas expense, production taxes and ad valorem taxes related to the Aera assets following the completion of the Aera Merger.

Accretion expense — Accretion expense for the nine months ended September 30, 2025 was $85 million compared to $56 million for the nine months ended September 30, 2024. The increase was primarily due to the addition of the Aera asset retirement liability assumed as of July 1, 2024 in connection with the Aera Merger.

Net loss on natural gas purchased derivatives — Net loss from derivatives related to our purchase of natural gas was $24 million for the nine months ended September 30, 2025 compared to a net loss of $11 million for the nine months ended September 30, 2024. The change 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. Gains and losses from our commodity derivative contracts are shown in the table below:


	Nine months ended
	September 30, 2025		September 30, 2024
	(in millions)
Non-cash loss (gain) on natural gas purchase derivatives	$	2	$	(7)
Settlements	22		18
Net loss on natural gas purchase derivatives	$	24	$	11

Other operating expenses, net — Other operating expenses, net decreased $61 million to $127 million for the nine months ended September 30, 2025 compared to $188 million for the nine months ended September 30, 2024.

For the nine months ended September 30, 2025 and September 30, 2024, other operating expenses, net includes the following:


	Nine months ended
	September 30, 2025		September 30, 2024

	(in millions)
Carbon management business expense	$	42	$	36
Transaction and integration costs	10		56
Energy costs due to downtime at Elk Hills power plant	—		44
Severance	8		28
Litigation and settlement related expenses (a)	26		7
Offshore platforms maintenance and abandonment	7		2
Information technology infrastructure	11		—
All other	23		15
Total operating expenses, net	$	127	$	188

(a) See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for more information on a $25 million payment we made to CalGEM during the nine months ended September 30, 2025.

Interest and debt expense, net — Interest and debt expense, net was $77 million for the nine months ended September 30, 2025 compared to $59 million for the nine months ended September 30, 2024. The increase was predominantly due to higher interest expense resulting from the issuance of our 2029 Senior Notes. In June 2024, we issued $600 million in aggregate principal amount of 2029 Senior Notes and in August 2024, we completed a follow-on offering of $300 million in aggregate principal amount of 2029 Senior Notes.

Income taxes – The income tax provision for the nine months ended September 30, 2025 was $128 million (representing an effective tax rate of 27%), compared to a provision of $132 million (representing an effective tax rate of 28%) for the nine months ended September 30, 2024. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes for additional information on our income taxes.

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 15 Condensed Consolidated Financial Information.

Results of Our Oil and Natural Gas Operations

The following table includes financial results and key operating data for our oil and natural gas segment for the three months ended September 30, 2025 and June 30, 2025 and the nine months ended September 30, 2025 and 2024.


	Three months ended				Nine months ended
	September 30,		June 30,		September 30,		September 30,
	2025		2025		2025		2024

	(in millions, except as otherwise stated)

Production and oil and gas segment financial data
Net production sold (MBoe/d)	137		137		138		99
Total operating revenues	$	728	$	714	$	2,272	$	1,734
Segment profit	$	182	$	194	$	642	$	547

Items affecting comparability:

Net (loss) gain on asset divestitures (a)	$	(1)	$	—	$	(1)	$	6

Key operating expenses per Boe
Operating costs	$	25.54	$	24.19	$	25.11	$	24.11
Operating costs, after hedges on purchased natural gas	$	25.75	$	24.75	$	25.68	$	24.76
General and administrative expenses (b)	$	0.72	$	0.72	$	0.80	$	2.65
Depreciation, depletion and amortization (c)	$	9.39	$	9.69	$	9.68	$	8.55
Taxes other than on income	$	4.54	$	3.28	$	4.16	$	5.05

(a) Net loss on asset divestitures for the three and nine months ended September 30, 2025 related to the sale of oil and gas assets located in Ventura. Net gain on asset divestitures for the nine months ended September 30, 2024 related to the sale of our Fort Apache parcel in Huntington Beach.

(b) Includes general and administrative expenses allocated to our oil and natural gas segment.

Production, Prices, and Realizations

Net Production Sold

The following table presents our net production sold per day in each of the California basins in which we operate for the periods presented. The amounts in the production table below include volumes produced from operated and non-operated fields for each of the periods presented.


	Three months ended		Nine months ended
	September 30,	June 30,	September 30,	September 30,
	2025	2025	2025	2024
Oil (MBbl/d)
San Joaquin Basin	81	83	83	50
Los Angeles Basin	17	17	17	17
Other Basins	9	9	9	2

Total	107	109	109	69
NGLs (MBbl/d)
San Joaquin Basin	10	10	10	11



Total	10	10	10	11
Natural gas (MMcf/d)
San Joaquin Basin	103	96	100	99
Los Angeles Basin	1	1	1	1
Sacramento Basin	11	12	12	14
Other Basins	3	2	2	—
Total	118	111	115	114

Total Net Production Sold (MBoe/d)	137	137	138	99

Total average net production sold remained flat at 137 MBoe/d for the three months ended September 30, 2025 compared to the three months ended June 30, 2025. Our production-sharing contracts (PSCs), which are described below, positively impacted our net oil production by 1 MBoe/d in the three months ended September 30, 2025 compared to the three months ended June 30, 2025. This positive production impact was offset by natural decline.

Total average net production sold increased to 138 MBoe/d for the nine months ended September 30, 2025 compared to 99 MBoe/d for the nine months ended September 30, 2024. The increase was primarily a result of the Aera Merger. Our PSCs, which are described below, positively impacted our net oil production by approximately 2 MBoe/d in the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024.

Production-Sharing Contracts

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.

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 2024 Annual Report.

Prices and Realizations

The following tables set forth the average realized prices and price realizations on the commodities we sell as a percentage of average Brent, WTI and NYMEX Henry Hub indexes for our oil and natural gas operations for the periods presented:


	Three months ended
	September 30, 2025			June 30, 2025
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	68.13		$	66.76

Realized price without derivative settlements	$	66.32	97%	$	65.07	97%
Derivative settlements	0.72			1.66
Realized price with derivative settlements	$	67.04	98%	$	66.73	100%

WTI	$	64.93		$	63.74

Realized price without derivative settlements	$	66.32	102%	$	65.07	102%
Realized price with derivative settlements	$	67.04	103%	$	66.73	105%

Natural Gas Liquids ($ per Bbl)
Realized price (% of Brent)	$	41.04	60%	$	42.41	64%
Realized price (% of WTI)	$	41.04	63%	$	42.41	67%

Natural gas
NYMEX Henry Hub ($/MMBtu)	$	3.07		$	3.44

Realized price ($/Mcf)	$	3.47	113%	$	2.79	81%


	Nine months ended
	September 30, 2025			September 30, 2024
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	69.94		81.79

Realized price without derivative settlements	$	68.34	98%	$	79.15	97%
Derivative settlements	0.27			(2.05)
Realized price with derivative settlements	$	68.61	98%	$	77.10	94%

WTI	$	66.70		$	77.54

Realized price without derivative settlements	$	68.34	102%	$	79.15	102%
Realized price with derivative settlements	$	68.61	103%	$	77.10	99%

Natural Gas Liquids ($ per Bbl)
Realized price (% of Brent)	$	46.10	66%	$	47.77	58%
Realized price (% of WTI)	$	46.10	69%	$	47.77	62%

Natural gas
NYMEX Henry Hub ($/MMBtu)	$	3.39		$	2.10

Realized price ($/Mcf)	$	3.46	102%	$	2.76	131%

Oil — Brent price movements in 2025 have been dominated by OPEC+ signaling higher output, which put downward pressure on prices during the three months ended June 30, 2025. Brent prices rebounded during the three months ended September 30, 2025 as output was lower than expected and seasonal demand. Brent oil prices were lower for the nine months ended September 30, 2025 compared to the same period in 2024 as OPEC+ shifted their production cuts and quotas to increase supply. See Business Environment and Industry Outlook above for more information on factors influencing Brent commodity prices for the periods presented.

NGLs — Prices for natural gas liquids during the three months ended September 30, 2025 decreased compared to the three months ended June 30, 2025, reflecting typical seasonal patterns. Prices for natural gas liquids during the nine months ended September 30, 2025 were lower than in the same prior year period, consistent with broader declines in oil commodity prices.

Natural Gas — Natural gas index prices decreased for the three months ended September 30, 2025 compared to the three months ended June 30, 2025 driven by substantial natural gas production relative to modest demand for electricity generation. Realized natural gas prices in California were higher in the three months ended September 30, 2025 compared to the three months ended June 30, 2025 reflecting pipeline system maintenance and constraints impacting natural gas deliveries into California. Natural gas prices increased for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 driven by higher demand in 2025 and the effects of elevated inventories in the prior year.

Results of Our Carbon Management Segment

Our carbon management segment, which we refer to as Carbon TerraVault, primarily pursues the development of CCS projects. We expect that our Carbon TerraVault CCS projects will inject CO 2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO 2 deep underground. We also expect to invest in projects that rely on CCS technology in connection with reducing our own emissions. In addition, we may participate in the development of projects that are the source of these CO 2 emissions. Our carbon management segment is in its early stages of development. We expect construction of our first carbon capture project at our cryogenic gas processing facility to be completed at or around year end. We expect first injection in 2026, subject to receipt of final regulatory approvals.

The following tables include results for our carbon management segment for the three months ended September 30, 2025 and June 30, 2025 and the nine months ended September 30, 2025 and September 30 2024.


	Three months ended				Nine months ended
	September 30,		June 30,		September 30,		September 30,
	2025		2025		2025		2024

	(in millions)				(in millions)
Segment loss	$	(21)	$	(20)	$	(66)	$	(63)


	Three months ended				Nine months ended
	September 30,		June 30,		September 30,		September 30,
	2025		2025		2025		2024

	(in millions)				(in millions)
Carbon management expenses	$	10	$	14	$	42	$	36
Segment general and administrative expenses	$	4	$	3	$	10	$	10
Loss from investment in the Carbon TerraVault JV	$	2	$	1	$	4	$	10

Carbon management expenses decreased for the three months ended September 30, 2025 compared to the t hree months ended June 30, 2025 as a result of lower legal and compensation expenses.

Carbon management expenses increased for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 as a result of increased expenditure related to the evaluation of CCS projects and increased lease cost.

Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity and capital resources are cash flows from operations, available 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 and nine months ended September 30, 2025 were for repurchases of our common stock, payment of dividends, and capital investments.

The following table summarizes our liquidity:



	September 30, 2025
	(in millions)
Available cash and cash equivalents (a)	$	180
Revolving Credit Facility:
Borrowing capacity	$	1,150

Outstanding letters of credit	(176)
Availability	$	974

Liquidity	$	1,154

(a) Excludes restricted cash of $16 million.

At current commodity prices and based upon our planned 2025 capital program described below, we expect to generate operating cash flow to return cash to shareholders through dividends and repurchases of our common stock. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or share repurchases to the extent permitted under our Revolving Credit Facility, our 8.25% senior notes due 2029 (2029 Senior Notes), and our 7.00% senior notes due 2034 (2034 Senior Notes) (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We continue to monitor the current macroeconomic environment and will adjust our planned uses of cash as necessary. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.

Revolving Credit Facility

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt in our 2024 Annual Report for information on the Revolving Credit Facility and related amendments. See Part I, Item 1 – Financial Statements, Note 16 Subsequent Events for information on a recent amendment to our Revolving Credit Facility.

2034 Senior Notes

See Part I, Item 1 – Financial Statements, Note 16 Subsequent Events for information on our 2034 Senior Notes.

2026 Senior Notes Redemption

See Part I, Item 1 – Financial Statements, Note 4 Debt and Note 16 Subsequent Events for information on the redemption of our 2026 Senior Notes.

Share Repurchase Program

See Part I, Item 1 – Financial Statements, Note 10 Stockholders' Equity and Part II, Item 2 – Other Information, Unregistered Sales of Equity Securities and Use of Proceeds for more information on our Share Repurchase Program.

Dividends

See Part I, Item 1 – Financial Statements, Note 10 Stockholders' Equity for more information on our dividends. See Part I, Item 1 – Financial Statements, Note 16 Subsequent Events for information on an increased dividend declared in November 2025.

Capital Program

Our capital investment for the nine months ended September 30, 2025 was $202 million. We expect our full year 2025 capital program to range between $280 million and $330 million. Of this amount, $250 million to $275 million is related to our oil and natural gas segment, $20 million to $40 million is for our carbon management segment and $10 million to $15 million is for corporate and other activities. The above amounts related to carbon management projects do not include amounts funded by Brookfield through the Carbon TerraVault JV, such as drilling injection and monitoring wells at our 26R reservoir.

With respect to oil and natural gas development, we ran an average of two rigs during the three months ended September 30, 2025 and expect to exit the year with four rigs. Refer to Regulatory Updates above for more information on permitting. Refer to Part I, Item 1 – Financial Statements, Note 9 Segment Information for information on capital investment by segment.

We plan to average four rigs during 2026, which activity is underpinned by the strength of hedges currently in place. We expect to operate four rigs using existing permits and new permits which we expect to become available in 2026 following the recent enactment of SB 237. We retain the flexibility to adjust our 2026 capital plan to reflect changes in commodity prices and other market factors. This program does not include the impact of the Berry Merger.

Derivatives

Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining oil prices negatively affect our operating cash flow, and the inverse applies during periods of rising oil 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, 2025. 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, 2025 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt in our 2024 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

Cash Flow Analysis

Cash flows from operating activities — For the nine months ended September 30, 2025, our operating cash flow increased by $226 million to $630 million from $404 million in the same period in 2024. This increase in operating cash flow was primarily driven by the Aera Merger on July 1, 2024.

Oil production during the nine months ended September 30, 2025 as compared to the same period in 2024 increased 40 MBbl/d from 69 MBbl/d to 109 MBbl/d as a result of the Aera Merger. Higher revenue from this increase in production was partially offset by lower average realized oil prices (after derivative settlements). Average realized prices for oil decreased by $8.49 per barrel to $68.61 in the nine months ended September 30, 2025 from $77.10 in the same prior year period. Further, as a result of the Aera Merger, we experienced higher operating costs, employee costs, well abandonment costs, production taxes and greenhouse gas taxes during the nine months ended September 30, 2025 as compared to the same prior year period.

During the nine months ended September 30, 2024, downtime at the Elk Hills power plant negatively impacted our production and we purchased electricity at higher prices.

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,
		2025		2024

		(in millions)
Capital investments		$	(202)	$	(167)
Changes in accrued capital investments		(10)		8
Proceeds from asset divestitures		2		12
Purchase of a business, net of cash acquired		—		(853)
Acquisitions		—		(6)


Other, net		(7)		(4)
Net cash used in investing activities		$	(217)	$	(1,010)

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,
		2025		2024

		(in millions)
Proceeds from Revolving Credit Facility		$	150	$	30
Repayments of Revolving Credit Facility		(150)		(30)
Proceeds from 2029 Senior Notes, net		—		888



Repurchases of common stock (a)		(352)		(135)
Common stock dividends		(102)		(77)
Dividend equivalents on equity-settled awards		(1)		(4)

Issuance of common stock		2		2
Bridge loan commitment costs		—		(5)
Debt redemption		(123)		(303)
Debt amendment costs		—		(10)
Debt issuance costs		(1)		—
Stock warrants exercised		—		37

Shares cancelled for taxes		(12)		(42)
Net cash (used in) provided by financing activities		$	(589)	$	351

(a) Note: The total value of shares purchased includes excise taxes, which are generally paid in the year following the share repurchase. Commissions paid on share repurchases were not significant in all periods presented.

For the nine months ended September 30, 2025, our cash flow used in financing activities was $589 million compared to cash flow provided by financing activities of $351 million in the same period in 2024. This decrease in cash flow from financing activities was primarily driven by the $888 million of proceeds from 2029 Senior Notes issued in the nine months ended September 30, 2024. Additionally, the decrease is caused by the $352 million cash outflow used to repurchase stock in the nine months ended September 30, 2025 compared to $135 million in the nine months ended September 30, 2024.

Divestitures and Assets Held for Sale

See Part I, Item 1 – Financial Statements, Note 8 Divestitures and Assets Held for Sale for information on our divestitures and acquisitions during the three months ended September 30, 2025 and 2024.

Lawsuits, Claims, Commitments and Contingencies

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 2024 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” or “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

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

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

• the ability to successfully execute integration efforts in connection with the Aera Merger, 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 segment; (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 expected timing and resumption of the issuance of well permits following the enactment of SB 237;

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

• the impact of inflation, tariffs and changes in domestic or global trade policies 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, power 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 segment 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 segment;

• 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;

• transaction costs;

• unknown liabilities

• the risk that any announcements relating to the Berry Merger could have adverse effects on the market price of our common stock;

• the ability to successfully integrate Berry;

• the ability to achieve projected synergies from the Berry Merger or it may take longer than expected to achieve synergies;

• risks related to financial community and rating agency perceptions of us and our business, operations, financial condition and the industry in which we operate;

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

• the risk that stockholders of Berry may not approve the Berry Merger;

• the risk that the any of the other closing conditions to the Berry Merger may not be satisfied in a timely manner, including the risk that all necessary regulatory approvals may not be obtained or may be obtained subject to conditions that are not anticipated;

• risks related to disruption of management time from ongoing business operations due to the Berry transaction;

• effects of the announcement, pendency or completion of the transaction on our ability to retain customers and retain and hire key personnel and maintain relationships with our suppliers and customers; and

• other factors discussed in Part I, Item 1A – Risk Factors of our 2024 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, 2025, 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 2024 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, 2025, we had a net asset of $71 million for our commodity derivative positions which are carried at fair value. For more information on our derivative positions as of September 30, 2025 , refer to Part I, Item 1 – Financial Statements, Note 6 Derivatives.

As of September 30, 2025, we have hedges on approximately 69% of our expected oil production for the remainder of 2025 at a weighted average floor price of $66.60. As of September 30, 2025, our hedges for purchased natural gas approximate 69% of our expected fuel use in oil and natural gas operations for the remainder of 2025 at a fixed price of $4.01.

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, 2025, 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, 2025 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, 2025 . Our 2029 Senior Notes bear interest at a fixed rate of 8.250% per annum. Our 2034 Senior Notes bear interest at a fixed rate of 7.000% 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, 2025.

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, 2025 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 5 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 2024 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 2024 Annual Report. There were no material changes to those risk factors during the three months ended September 30, 2025, except as described below.

Acquisition and disposition activities, including the Berry Merger, involve substantial risks.

On September 14, 2025, we entered into the Berry Merger Agreement with Berry. In addition, from time to time, we engage in acquisition activities. The Berry Merger and other such activities carry risks that we may:

• not fully realize anticipated benefits due to less-than-expected reserves or production or changed circumstances;

• bear unexpected integration costs or experience other integration difficulties;

• assume liabilities that are greater than anticipated; and

• be exposed to currency, political, marketing, labor and other risks.

In connection with our acquisitions, we are often only able to perform limited due diligence. Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing for recovering the reserves, exploration potential, future commodity prices, operating costs and potential environmental, regulatory and other liabilities. Such assessments are inexact and incomplete, and we may be unable to make these assessments with a high degree of accuracy.

The Berry Merger is expected to close in the first quarter of 2026 and is subject to certain closing conditions, including, among others, adoption of the Berry Merger Agreement by its stockholders, the receipt of certain required government approvals, and other customary closing conditions. Our other acquisition activities may similarly require us to seek approvals from government agencies and other regulatory bodies, depending on the nature and extent of the businesses being acquired. There can be no assurances that we would be able to obtain such approvals. If we are not able to complete acquisitions, we may not be able to grow our reserves or develop our properties in a timely manner or at all.

We regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Our disposition activities carry risks that we may:

• not be able to realize reasonable prices or rates of return for assets;

• be required to retain liabilities that are greater than desired or anticipated;

• experience increased operating costs; and

• reduce our cash flows if we cannot replace associated revenue.

There can be no assurance that we will be able to divest assets on financially attractive terms or at all. Our ability to sell assets is also limited by the agreements governing our indebtedness. If we are not able to sell assets as needed, we may not be able to generate proceeds to support our liquidity and capital investments.

In addition, we have expended and will continue to expend significant time and resources in connection with the Berry Merger, as well as any future acquisition and disposition activities. For example, time and resources will be expended in connection with seeking regulatory approvals for the Berry Merger.

While the Berry Merger is pending, we will be subject to certain contractual restrictions that could adversely affect our business and operations.

Due to certain restrictions in the Berry Merger Agreement on the conduct of business prior to completing the Berry Merger, we may be unable, during the pendency of the Berry Merger, to pursue strategic transactions and otherwise pursue other actions, even if such actions would prove beneficial, and we may have to forgo certain opportunities we might otherwise pursue.

In addition, the Berry Merger Agreement also contains certain termination rights for us and Berry. Upon termination of the Berry Merger Agreement in accordance with its terms, under certain circumstances, we will be required to reimburse Berry up to $5 million for certain costs and expenses incurred or paid by Berry in connection with the Berry Merger. In addition, upon a termination of the Berry Merger Agreement resulting from our fraud or willful breach of the Berry Merger Agreement, we may be liable to Berry, under certain circumstances, for damages up to $40,255,219, only to the extent proven, based on the loss of the premium that the Berry stockholders would have received if the Berry Merger was consummated pursuant to the terms of the Berry Merger Agreement and Section 261(a)(1) of the Delaware General Corporation Law.

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds

Share Repurchases

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.35 billion of our common stock through June 30, 2026. 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 either retired or held as treasury stock.

Our share repurchase activity for the three months ended September 30, 2025 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, 2025 - July 31, 2025

—

August 1, 2025 - August 31, 2025

—

September 1, 2025 - September 30, 2025

—

Total

—

(a) The total value of shares that may yet be purchased under the Share Repurchase Program totaled $205 million as of September 30, 2025.

Item 5 Other Disclosures

Restricted Stock Units

On November 4, 2025, the Board of Directors approved the grant of restricted stock unit awards (RSUs) under our 2021 Long Term Incentive Plan to certain executive officers of the Company in order to provide a one-time retention award to our management team. The amount of restricted stock units granted to each executive officer is as follows:


Name			Number of Restricted Stock Units
Francisco J. Leon			84,710
Michael L. Preston			47,649
Clio Crespy			42,355
Omar Hayat			42,355
Jay A. Bys			26,472
Chris D. Gould			26,472

The RSUs are eligible to vest, subject to the grantee’s continuous employment, according to the following schedule: 10% of the RSUs will vest each on the first, second, and third annual anniversaries of the grant date; (ii) 30% of the RSUs will vest on the fourth annual anniversary of the grant date; and (iii) 40% of the RSUs will vest on the fifth annual anniversary of the grant date. Vested RSUs are settled in shares of the Company’s common stock.

Upon a termination of grantee’s employment by the Company without cause, by the grantee for good reason or due to death or disability, any unvested RSUs will vest in full, but will not be paid until the original settlement dates. Upon grantee’s retirement, any unvested RSUs continue to vest on the original vesting schedule. In the event of a change in control, any unvested RSUs vest in full if the grantee remains continuously employed through such change in control. Any unvested RSUs are subject to forfeiture in the event of all other terminations of employment. Vested and unvested RSUs will also be subject to special clawback provisions in the event of a termination for cause, and will be subject to our general compensation recovery and clawback policies, applicable law and stock exchange rules.

The foregoing description of the RSUs is not complete and is qualified in its entirety by reference to the full text of the RSU award, the form of which is attached as Exhibit 10.5 on this Quarterly Report on Form 10-Q and incorporated herein by reference.

Rule 10b5-1 Trading Arrangements

During the three months ended September 30, 2025, no 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


2.1**			A greement and Plan of Merger, dated September 14, 2025, by and among California Resources Corporation, Berry Corporation (bry) and Dornoch Merger Sub, LLC (filed as Exhibit 2.1 to Registrant's Current Report on Form 8- K file d on September 17, 2025 and incorporated her e in by reference).

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			I ndenture , dated October 8, 2025, by and among the Company, the Guarantors and the Trustee (fi led as Exhibit 4.1 to Registrant's Current Report on Form 8-K filed on October 8, 2025 and incorporated herein by reference).

10.1**			Amended and Restated Employment Agreement by and between Jay A. Bys and California Resources Corporation, dated August 4, 2025 ( filed as Exhibit 10. 1 to Registrant's Quarterly Report on Form 10-Q filed August 6, 2025 and incorporated herein by reference)

10.2**			Amended and Restated Employment Agreement by and between Michael L. Preston and California Resources Corporation, dated August 4, 2025 ( filed as Exhibit 10.2 to Registrant's Quarterly Report on Form 10-Q filed August 6, 2025 and incorporated herein by reference).

10.3			S ixth Amendment to Amended and Restated Credit Agreement, entered into effective as of September 22, 2025 , by and among California Resources Corporation, as the Borrower, the several lenders from time to time parties thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on September 24, 2025 and incorporated herein by reference).

10.4			S eventh Amendment to Amended and Restated Credit Agreement, entered into effective as of October 29, 2025 , by and among California Resources Corporation, as the Borrower, the several lenders from time to ti me parties thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.1 to Registrant's Current Report on Form 8 -K filed on October 31, 2025 and incorporated herein by referen ce).

10.5*			Form of California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit Award Terms and Conditions.

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 5, 2025	/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, 2025

Exhibits