CRC 10-Q Quarterly Report March 31, 2025

CALIFORNIA RESOURCES CORP

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crc-20250331

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 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 March 31, 2025 was 89,175,034 .

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 (Loss)	6
	Condensed Consolidated Statements of Stockholders' Equity	7
	Condensed Consolidated Statements of Cash Flows	8
	Notes to the Condensed Consolidated Financial Statements	9
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
	General	29
	Business Environment and Industry Outlook	29
	Regulatory Updates	30
	Responsible Net Zero Goal	31
	Statements of Operations Analysis	32
	Results of Our Oil and Natural Gas Operations	36
	Results of Our Carbon Management Segment	39
	Liquidity and Capital Resources	39
	Divestitures and Assets Held for Sale	43
	Lawsuits, Claims, Commitments and Contingencies	43
	Critical Accounting Estimates and Significant Accounting and Disclosure Changes	43
	Forward-Looking Statements	44
Item 3	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4	Controls and Procedures	46

Part II
Item 1	Legal Proceedings	47
Item 1A	Risk Factors	47
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 5	Other Disclosures	47
Item 6	Exhibits	48

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.

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

• MHp - One thousand horsepower.

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

• MMBoe - One million barrels of oil equivalent.

• MMBtu - One million British thermal units.

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

• MMT - Million metric tons.

• MMTPA - Million metric tons per annum.

• MW - Megawatts of power.

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

• NYMEX - The New York Mercantile Exchange.

• OCTG - Oil country tubular goods.

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

• OPEC - Organization of the Petroleum Exporting Countries.

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

• PHMSA - Pipeline and Hazardous Materials Safety Administration.

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

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

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

• PSCs - 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. Refer to Part I, Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Responsible Net Zero Goal for more information.

• 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 March 31, 2025 and December 31, 2024

(in millions, except share data)


	March 31,		December 31,
	2025		2024
	(unaudited)		(audited)
CURRENT ASSETS
Cash and cash equivalents	$	214	$	372
Trade receivables	308		330
Inventories	91		90
Assets held for sale	10		10
Receivable from affiliate	43		46
Other current assets, net	133		176
Total current assets	799		1,024
PROPERTY, PLANT AND EQUIPMENT	6,808		6,738
Accumulated depreciation, depletion and amortization	( 1,190 )		( 1,058 )
Total property, plant and equipment, net	5,618		5,680
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	82		86
DEFERRED INCOME TAXES	60		73
OTHER NONCURRENT ASSETS	268		272
TOTAL ASSETS	$	6,827	$	7,135


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


Accounts payable	340		369


Accrued liabilities	499		611

Total current liabilities	961		980
NONCURRENT LIABILITIES
Long-term debt, net	888		1,132

Asset retirement obligations	989		995
Deferred tax liability	134		113
Other long-term liabilities	339		377



STOCKHOLDERS' EQUITY
Preferred stock ( 20,000,000 shares authorized at $ 0.01 par value) no shares outstanding at March 31, 2025 and December 31, 2024	—		—
Common stock ( 200,000,000 shares authorized at $ 0.01 par value) ( 109,960,216 and 109,613,585 shares issued; 89,175,034 and 91,100,322 shares outstanding at March 31, 2025 and December 31, 2024)	1		1
Treasury stock ( 20,785,182 shares held at cost at March 31, 2025 and 18,513,263 shares held at cost at December 31, 2024)	( 897 )		( 796 )
Additional paid-in capital	2,580		2,578
Retained earnings	1,759		1,680
Accumulated other comprehensive income	73		75


Total stockholders' equity	3,516		3,538
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	6,827	$	7,135

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

CALIFORNIA R ESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations (unaudited)

For the three months ended March 31, 2025 and 2024

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


	Three months ended March 31,
	2025		2024
REVENUES
Oil, natural gas and natural gas liquids sales	$	814	429
Net gain (loss) from commodity derivatives	6		( 71 )
Revenue from marketing of purchased commodities	64		74
Electricity revenue	22		15
Interest and other revenue	6		7
Total operating revenues	912		454

OPERATING EXPENSES
Operating costs	316		176
General and administrative expenses	72		57
Depreciation, depletion and amortization	131		53

Taxes other than on income	70		38

Costs related to marketing of purchased commodities	50		54
Electricity generation expenses	10		8
Transportation costs	20		20
Accretion expense	29		12
Net (gain) loss on natural gas purchase derivatives	( 6 )		1

Measurement period adjustments	1		—
Other operating expenses, net	33		45
Total operating expenses	726		464
Gain on asset divestitures	—		6

OPERATING INCOME (LOSS)	186		( 4 )

NON-OPERATING (EXPENSES) INCOME

Interest and debt expense	( 27 )		( 13 )
Loss on early extinguishment of debt	( 1 )		—
Loss from investment in unconsolidated subsidiaries	( 1 )		( 3 )
Other non-operating income	5		1
INCOME (LOSS) BEFORE INCOME TAXES	162		( 19 )
Income tax (provision) benefit	( 47 )		9
NET INCOME (LOSS)	$	115	$	( 10 )






Net income (loss) per share
Basic	$	1.27	$	( 0.14 )
Diluted	$	1.26	$	( 0.14 )

Weighted-average common shares outstanding
Basic	90.6		69.0
Diluted	91.2		69.0

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Comprehensive Income (Loss) (unaudited)

For the three months ended March 31, 2025 and 2024

(in millions)


	Three months ended March 31,
	2025		2024
Net income (loss)	$	115	$	( 10 )
Other comprehensive income (loss) (a) :

Amortization of prior service cost credit included in net periodic benefit cost, net of tax	( 2 )		( 2 )

Comprehensive income (loss)	$	113	$	( 12 )

(a) Tax effects of the amortization of prior service cost credit were insignificant for the three months ended March 31, 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 months ended March 31, 2025 and 2024

(in millions)


	Three months ended March 31, 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	—		—		—		115		—		115

Share-based compensation	—		—		6		—		—		6


Repurchases of common stock	—		( 101 )		—		—		—		( 101 )


Issuance of common stock	—		—		6		—		—		6
Cash dividend ($ 0.3875 per share)	—		—		—		( 36 )		—		( 36 )
Shares cancelled for taxes	—		—		( 11 )		—		—		( 11 )
Other	—		—		1		—		—		1
Other comprehensive income, net of tax	—		—		—		—		( 2 )		( 2 )
Balance, March 31, 2025	$	1	$	( 897 )	$	2,580	$	1,759	$	73	$	3,516


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

Share-based compensation	—		—		7		—		—		7



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

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

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 months ended March 31, 2025 and 2024

(in millions)


	Three months ended March 31,
	2025		2024
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)	$	115	$	( 10 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	131		53
Deferred income tax provision (benefit)	35		( 9 )

Net (gain) loss from commodity derivatives	( 12 )		72
Net payments on settled commodity derivatives	( 28 )		( 14 )
Net loss on early extinguishment of debt	1		—

Gain on asset divestitures	—		( 6 )



Other non-cash charges to income, net	10		6
Net changes in operating assets and liabilities	( 66 )		( 5 )
Net cash provided by operating activities	186		87

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	( 55 )		( 54 )
Changes in accrued capital investments	( 21 )		( 4 )
Proceeds from asset divestitures	—		10




Other, net	( 3 )		( 1 )
Net cash used in investing activities	( 79 )		( 49 )

CASH FLOW FROM FINANCING ACTIVITIES




Repurchases of common stock	( 101 )		( 58 )
Common stock dividends	( 35 )		( 21 )
Dividend equivalents on equity-settled awards	( 1 )		( 4 )




Issuance of common stock	6		1
Bridge loan commitments	—		( 8 )


Shares cancelled for taxes	( 11 )		( 41 )
Debt redemption	( 123 )		—

Net cash used in financing activities	( 265 )		( 131 )
Decrease in cash and cash equivalents	( 158 )		( 93 )
Cash and cash equivalents—beginning of period	372		496
Cash and cash equivalents—end of period	$	214	$	403

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

March 31, 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 (the Merger Agreement), we obtained all of the ownership interests in Aera Energy LLC (Aera) (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 three months ended March 31, 2025 as compared to the three months ended March 31, 2024. See Note 2 Aera Merger 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.

NOTE 2 AERA MERGER

On July 1, 2024, we obtained by way of merger all of the ownership interests in Aera. Aera is a leading operator of mature fields in California, primarily in the San Joaquin and Ventura basins, with high oil-weighted production. The Aera Merger adds significant proved developed reserves to CRC. In connection with the closing of the Aera Merger, we issued 21,315,707 shares of common stock to the former Aera owners (Sellers). We issued an additional 107,265 shares in February 2025 and we expect to issue an additional 238,828 shares for deferred consideration. This deferred consideration is related to pre-effective date and restructuring income taxes of the Sellers. We also paid approximately $ 990 million in connection with the extinguishment of all of Aera's outstanding indebtedness using the proceeds from the issuance of our 8.25 % senior notes due 2029 (2029 Senior Notes) and cash on hand. For more information on the 2029 Senior Notes, refer to Note 4 Debt.

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

At the date of this filing, our assessment of the fair value of assets acquired and liabilities assumed is not complete. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, final appraisals of Aera's assets, measurement of leases, valuation of certain accrued liabilities, determination of Aera's asset retirement obligations and preparation of tax returns that will provide underlying tax basis of the assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period subsequent to the Aera Merger closing date and adjustments may be made to the provisional amounts recorded as of March 31, 2025.

We have measured assets and liabilities at acquisition date fair value on a nonrecurring basis.

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
Deferred consideration obligation	13
Total purchase consideration	$	2,144

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


	Preliminary Purchase Price Allocation as of December 31, 2024		Adjustments		Preliminary Purchase Price Allocation as of March 31, 2025
	(in millions)
Assets Acquired
Cash	$	137	$	—	$	137
Accounts receivable	176		—		176
Inventories	30		( 1 )		29
Other current assets	49		1		50
Investment in unconsolidated subsidiary	59		( 7 )		52
Property, plant and equipment	3,048		14		3,062
Pension and other postretirement benefits	73		—		73
Other noncurrent assets	57		13		70
Total Assets Acquired	3,629		20		3,649

Liabilities Assumed
Accounts payable	( 158 )		—		( 158 )
Accrued liabilities	( 157 )		( 3 )		( 160 )
Asset retirement obligations	( 646 )		—		( 646 )
Fair value of derivative contracts	( 351 )		—		( 351 )
Pension and other postretirement benefits	( 35 )		—		( 35 )
Deferred tax liability	( 101 )		1		( 100 )

Other long-term liabilities	( 37 )		( 18 )		( 55 )
Total Liabilities Assumed	( 1,485 )		( 20 )		( 1,505 )
Net Assets Acquired	$	2,144	$	—	$	2,144

Supplemental Pro Forma Information (unaudited)

The following supplemental pro forma financial information presents the condensed consolidated results of operations for the three months ended March 31, 2024 as if the Aera Merger had occurred on January 1, 2024.



	Three months ended March 31,
	2024

	(in millions)
Total operating revenue	$	613
Net loss (a)	$	( 286 )

Net loss per share
Basic	$	( 3.17 )
Diluted	$	( 3.17 )

(a) Reflects a net loss of $ 286 million primarily resulting from a significant net loss on commodity derivatives related to hedge positions held by Aera during the three months ended March 31, 2024.

The pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the Aera Merger been completed on January 1, 2024, nor is it necessarily indicative of future operating results of the combined entity. The pro forma financial information for the three months ended March 31, 2024 is a result of combining our three months statements of operations with Aera's pre-merger results from January 1, 2024 and the 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. Future results may vary significantly from the results reflected in the following pro forma information.

NOTE 3 INVESTMENTS AND RELATED PARTY TRANSACTIONS

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


	Midway Sunset Cogeneration Company
	(in millions)





Investment, December 31, 2024	$	59
Adjustment to the preliminary purchase price allocation (see Note 2 Aera Merger )	( 7 )


Investment, March 31, 2025	$	52


	Carbon TerraVault JV
	(in millions)
Investment, December 31, 2024	$	27
Loss from investment in unconsolidated subsidiary	( 1 )
Contributions	4
Investment, March 31, 2025	$	30

Midway Sunset Cogeneration Company

In July 2024, our merger with Aera led to our 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. (NRG). We recorded our investment in the Midway Sunset Cogeneration Company at $ 52 million as of March 31, 2025, which was $ 41 million in excess of the underlying assets of the partnership. This difference is associated with property, plant and equipment and we expect this amount will reverse over the remaining useful life of the power plant. 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 for the three months ended March 31, 2025 was not significant.

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 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.



	March 31,		December 31,
	2025		2024

	(in millions)

Receivable from affiliate (a)	$	43	$	46
Other long-term liabilities - contingent liability (b)	$	109	$	107

(a) The amount of Brookfield's contributions available to us and amounts due to us under a Master Services Agreement (MSA) are reported as receivable from affiliate. At March 31, 2025, the amount of $ 43 million includes the remaining $ 39 million of Brookfield's first and second installments of their initial investment which is available to us and $ 4 million related to the 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) The contingent liability relates to Carbon TerraVault JV put and call rights with respect to the 26R reservoir.

We recognized a loss of $ 1 million and $ 3 million for the three months ended March 31, 2025 and 2024, respectively, related to our investment in the Carbon TerraVault JV.

We are also performing well abandonment work at our Elk Hills field to prepare our 26R reservoir for injection of CO 2 . During the three months ended March 31, 2025 and 2024, we performed abandonment work and sought reimbursement in the amounts of $ 2 million and $ 4 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.

NOTE 4 DEBT

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



	March 31,		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	( 15 )		( 16 )
Unamortized premium	3		3
Total debt, net	1,010		1,132
Less: Current maturities	122		—
Long-term debt, net	$	888	$	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 March 31, 2025, $ 167 million letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters. As of March 31, 2025, we had $ 983 million of availability on our Revolving Credit Facility after taking into account $ 167 million in letters of credit outstanding. Our borrowing base of $ 1.5 billion is redetermined semi-annually and was re-affirmed in April 2025. There were no changes to the aggregate commitments of $ 1.15 billion as of May 7, 2025.

Note Redemptions

In the three months ended March 31, 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. There were no repurchases or redemptions of our 2026 Senior Notes in the three months ended March 31, 2024.

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).


	March 31,		December 31,
	2025		2024

	(in millions)

Fixed rate debt
2026 Senior Notes	$	122	$	245
2029 Senior Notes	915		913
Fair Value of Long-Term Debt	$	1,037	$	1,158

Other

As of March 31, 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 5 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

We, or certain of our subsidiaries, are involved, in the normal course of business, in lawsuits, environmental and other claims, and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties or injunctive or declaratory relief.

We accrue reserves for currently outstanding lawsuits, claims and proceedings when we determine it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances for these items at March 31, 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 accrued decommissioning obligations associated with these offshore platforms. Oxy sold its interest in the platforms approximately 30 years ago and it is our understanding that Oxy has not had any connection to the operations since that time and was challenging BSEE's order. Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy. In September 2021, we accepted the indemnification claim from Oxy and are challenging the order from BSEE. In March 2024, we entered into a cost sharing agreement with former lessees to share in ongoing maintenance costs during the pendency of the challenge to the BSEE order. We estimate our ongoing share of maintenance costs for the platforms are approximately $ 5 million per year. Due to the preliminary stage of the process, no cost estimates to abandon the offshore platforms have been determined.

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 purchased natural gas used in our steamflood operations. We did not have any derivative instruments designated as accounting hedges as of and for the three months ended March 31, 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 March 31, 2025:


	Q2 2025		Q3 2025		Q4 2025		2026		2027		2028
Sold Calls
Barrels per day	30,000		30,000		29,000		15,000		—		—
Weighted-average price per barrel	$	87.08	$	87.08	$	87.13	$	85.00	$	—	$	—

Purchased Puts
Barrels per day	30,000		30,000		29,000		15,000		—		—
Weighted-average price per barrel	$	61.67	$	61.67	$	61.72	$	60.00	$	—	$	—

Swaps
Barrels per day	46,506		45,001		42,626		30,449		13,882		1,697
Weighted-average price per barrel	$	71.31	$	70.63	$	69.94	$	67.95	$	65.53	$	65.00

At March 31, 2025, we also held the following swaps to hedge purchased natural gas used in our operations as shown in the table below.


	Q2 2025		Q3 2025		Q4 2025		2026		2027		2028

SoCal Border
MMBtu per day	29,074		25,750		22,408		660		—		—
Weighted-average price per MMBtu	$	3.44	$	3.48	$	3.53	$	6.29	$	—	$	—

NWPL Rockies
MMBtu per day	51,750		51,750		51,750		44,618		12,616		1,576
Weighted-average price per MMBtu	$	2.95	$	2.95	$	4.22	$	4.01	$	4.34	$	3.95

In the three months ended March 31, 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. We did not have similar positions during the three months ended March 31, 2025.

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
	March 31, 2025		March 31, 2024
	(in millions)
Non-cash commodity derivative gain (loss)	$	22	$	( 59 )
Net settlements and amortized premiums	( 16 )		( 12 )
Net gain (loss) from commodity derivatives	$	6	$	( 71 )

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
	March 31, 2025		March 31, 2024
	(in millions)
Non-cash gain on natural gas purchase derivatives	$	( 18 )	$	( 1 )
Settlements	12		2
Net (gain) loss on natural gas purchase derivatives	$	( 6 )	$	1

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 March 31, 2025 and December 31, 2024.


March 31, 2025
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value

	(in millions)
Other current assets, net	$	27	$	( 9 )	$	18
Other noncurrent assets	21		( 9 )		12

Current liabilities	( 39 )		9		( 30 )
Noncurrent liabilities	( 38 )		9		( 29 )
	$	( 29 )	$	—	$	( 29 )


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 March 31,
	2025			2024
	(in millions)
Income (loss) before income taxes	$	162		$	( 19 )

Current income tax provision	12			—
Deferred income tax provision (benefit)	35			( 9 )
Income tax provision (benefit)	$	47		$	( 9 )

Effective tax rate	29		%	47		%

Our income tax provision or benefit for interim periods is determined by applying an estimated annual effective tax rate to income (loss) before income taxes with the result adjusted for discrete items, if any, in the relevant period. A reconciliation of the U.S. federal statutory tax rate to our effective tax rate, including discrete items, for the three months ended March 31, 2025 and 2024 is shown below:


	Three months ended March 31,
	2025				2024
	Percent		Amount		Percent		Amount
U.S federal statutory tax rate	21	%	$	34	21	%	$	( 4 )
State income taxes, net of federal income tax effect (a)	7		12		7		( 1 )

Other	1		1		3		( 1 )
Annual effective tax rate	29	%	$	47	31	%	$	( 6 )
Discrete items recognized in the period:
Stock-based compensation and other	—		—		16		( 3 )

Effective tax rate	29	%	$	47	47	%	$	( 9 )

(a) State and local income taxes are predominantly in California.

During the three months ended March 31, 2024, we recognized an income tax benefit related to the settlement of certain equity-settled stock-based compensation awards, which had the effect of increasing our effective tax rate by 16 %.

NOTE 8 DIVESTITURES AND ASSETS HELD FOR SALE

Fort Apache in Huntington Beach

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

Carbon Management Assets

In 2022, we acquired properties for carbon management activities with the intent to divest a portion of these assets. The assets are carried at fair value and classified as held for sale as of March 31, 2025 on our condensed consolidated balance sheet.

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. 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 months ended March 31, 2025, and 2024.


	Three months ended March 31, 2025
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Elimination		Total

	(in millions)
Oil, natural gas and natural gas liquids sales	$	828	$	—	$	828	$	( 14 )	814



Other revenue	2		—		2		—		2

Segment operating revenues	$	830	$	—	$	830


Other revenues and income (a)									96




Total operating revenues									$	912

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


	Three months ended March 31, 2025
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Reconciliation (Income)/Expense		Total

	(in millions)
Segment operating revenues	$	830	$	—	$	830	$	—	$	830
Less:
Operating costs:
Energy operating costs	111		—		111		( 8 )		103
Gas processing costs	4		—		4		—		4
Non-energy operating costs	209		—		209		—		209
General and administrative expenses	12		3		15		57		72
Depreciation, depletion and amortization	126		—		126		5		131

Taxes other than on income	59		—		59		11		70


Interest expense	—		3		3		24		27
Loss from investment in unconsolidated subsidiaries	—		1		1		—		1


Other segment expenses (a)	43		18		61		—		61
Segment profit or (loss)	$	266	$	( 25 )	$	241




Other profit or loss (b)							( 12 )		( 12 )
Unallocated amounts (c)							2		2








Income before income taxes									$	162

(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.

(b) Other profit or loss includes the margin we earn from marketing activities and electricity margin.

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


	Three months ended March 31, 2024
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Elimination		Total

	(in millions)
Oil, natural gas and NGL sales to external customers	$	435	$	—	$	435	$	( 6 )	$	429



Other revenue	1		—		1		—		1

Segment operating revenues	$	436	$	—	$	436


Other revenues and income (a)									24




Total operating revenues									$	454

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


	Three months ended March 31, 2024
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Reconciliation (Income)/Expense		Total

	(in millions)
Segment operating revenues	$	436	$	—	$	436	$	—	$	436
Less:
Operating costs:
Energy operating costs	56		—		56		( 3 )		53
Gas processing costs	4		—		4		—		4
Non-energy operating costs	119		—		119		—		119
General and administrative expenses	9		2		11		46		57
Depreciation, depletion and amortization	49		—		49		4		53

Taxes other than on income	32		—		32		6		38


Interest expense	—		1		1		12		13
Loss from investment in unconsolidated subsidiary	—		3		3		—		3


Other segment expenses (a)	35		8		43		—		43
Segment profit or (loss)	$	132	$	( 14 )	$	118




Other profit or loss (b)							( 21 )		( 21 )
Unallocated amounts (c)							93		93








Income before income taxes									$	( 19 )

(a) Amounts for our oil and natural gas segment include purchases of wet gas processed by us, power and fuel costs purchased during maintenance at our Elk Hills power plant, transportation costs and accretion expense, net of a gain on asset divestitures. Amounts for our carbon management segment primarily include operating lease costs.

(b) Other profit or loss includes margin from purchased commodities and electricity margin.

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

The following table provides capital investment by segment and a reconciliation to our consolidated capital investment for the three months ended March 31, 2025 and 2024. We do not provide total assets by segment because this 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		Consolidated

	(in millions)
Three months ended March 31, 2025	$	42	$	2	$	11	$	55
Three months ended March 31, 2024	$	36	$	4	$	14	$	54

NOTE 10 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) were calculated using the treasury stock method for the three months ended March 31, 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 months ended March 31, 2025 and 2024:


	Three months ended March 31,
	2025		2024

	(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS
Net income (loss)	$	115	$	( 10 )





Denominator for Basic EPS
Weighted-average shares	90.6		69.0

Potential common shares, if dilutive:

Restricted stock units	0.4		—
Performance stock units	0.2		—

Denominator for Diluted EPS
Weighted-average shares	91.2		69.0

EPS
Basic	$	1.27	$	( 0.14 )
Diluted	$	1.26	$	( 0.14 )

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


	Three months ended March 31,
	2025	2024

	(in millions)
Shares issuable upon exercise of warrants	—	4.2
Shares issuable upon settlement of RSUs	—	0.9
Shares issuable upon settlement of PSUs	—	1.1
Total antidilutive shares	—	6.2

NOTE 11 PENSION AND POSTRETIREMENT BENEFIT PLANS

The following table sets forth the components of the net periodic benefit costs for our defined benefit pension and postretirement benefit plans for the three months ended March 31, 2025 and 2024:



	Three months ended March 31,				Three months ended March 31,
	2025				2024
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit

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




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

Contributions to our pension benefit plans were insignificant during the three months ended March 31, 2025 and the three months ended March 31, 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 12 SUPPLEMENTAL ACCOUNT BALANCES

Restricted cash — Cash and cash equivalents includes restricted cash of $ 15 million and $ 18 million at March 31, 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 March 31,
	2025		2024

	(in millions)
Oil	$	736	$	348
Natural gas	28		32
Natural gas liquids	50		49
Oil, natural gas and natural gas liquids sales	$	814	$	429

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 March 31,
	2025		2024

	(in millions)
Oil	$	22	$	20
Natural gas	36		48
Natural gas liquids	6		6
Revenue from marketing of purchased commodities	$	64	$	74

Inventories — 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. Inventories, by category, are as follows:


	March 31,		December 31,
	2025		2024

	(in millions)
Materials and supplies	$	88	$	86
Finished goods	3		4
Inventories	$	91	$	90

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


	March 31,		December 31,
	2025		2024

	(in millions)
Net amounts due from joint interest partners (a)	$	37	$	41

Fair value of commodity derivative contracts	18		14
Prepaid expenses	24		28
Greenhouse gas allowances	2		27

Income tax receivable	38		50

Other	14		16
Other current assets, net	$	133	$	176

(a) Included in the March 31, 2025 and December 31, 2024 net amounts due from joint interest partners are insignificant amounts of allowances.

Other noncurrent assets — Other noncurrent assets include the following:



	March 31,		December 31,
	2025		2024

	(in millions)
Operating lease right-of-use assets	$	100	$	105
Deferred financing costs - Revolving Credit Facility	24		23
Emission reduction credits	11		11

Fair value of commodity derivative contracts	12		16
Funded pension	67		67
Postretirement plan	13		13
Other	41		37
Other noncurrent assets	$	268	$	272

Accrued liabilities — Accrued liabilities include the following:


	March 31,		December 31,
	2025		2024

	(in millions)
Compensation-related liabilities	$	70	$	177
Postretirement and pension benefit plans	7		7
Taxes other than on income	94		100
Asset retirement obligations	144		134
Interest	25		12
Operating lease liability	22		15
Fair value of derivative contracts	30		50
Premiums due on commodity derivative contracts	11		14
Liability for settlement payments on commodity derivative contracts	1		1


Payables for funded projects	30		25


Payables to the former owners of Aera	20		29
Other	45		47
Accrued liabilities	$	499	$	611

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



	March 31,		December 31,
	2025		2024

	(in millions)
Compensation-related liabilities	$	36	$	50
Postretirement and pension benefit plans	57		59
Operating lease liability	64		76
Fair value of commodity derivative contracts	29		45

Contingent liability (related to Carbon TerraVault JV put and call rights)	109		107
Other	44		40
Other long-term liabilities	$	339	$	377

NOTE 13 SUPPLEMENTAL CASH FLOW INFORMATION

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


	Three months ended March 31,
	2025		2024

	(in millions)
Supplemental cash flow information
Interest paid, net of amount capitalized	$	9	$	20
Income taxes paid	$	—	$	22
Interest income	$	3	$	6

Supplemental disclosure of non-cash investing and financing activities
Contribution to the Carbon TerraVault JV	$	4	$	—
Issuance of shares for stock-based compensation awards	$	21	$	87
Dividends accrued for stock-based compensation awards	$	1	$	1
Excise tax on share repurchases	$	1	$	1

NOTE 14 CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have designated certain of our subsidiaries as Unrestricted Subsidiaries under the indenture governing our 2026 Senior Notes (2026 Senior Notes Indenture) and 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 March 31, 2025 and December 31, 2024 and the condensed consolidating statements of operations for the three months ended March 31, 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 March 31, 2025 and December 31, 2024


	As of March 31, 2025
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total current assets	$	259	$	45	$	495	$	—	$	799
Total property, plant and equipment, net	23		31		5,564		—		5,618
Investments in consolidated subsidiaries	5,108		( 37 )		12,780		( 17,851 )		—
Deferred tax asset	60		—		—		—		60
Investment in unconsolidated subsidiaries	—		30		52		—		82
Other assets	114		56		98		—		268
TOTAL ASSETS	$	5,564	$	125	$	18,989	$	( 17,851 )	$	6,827

Total current liabilities	248		19		694		—		961
Long-term debt	888		—		—		—		888
Asset retirement obligations	—		—		989		—		989
Other long-term liabilities	97		130		112		—		339
Deferred tax liability	134		—		—		—		134
Amounts due to (from) affiliates	681		28		( 709 )		—		—
Total equity	3,516		( 52 )		17,903		( 17,851 )		3,516
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	5,564	$	125	$	18,989	$	( 17,851 )	$	6,827


	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 months ended March 31, 2025 and 2024


	Three months ended March 31, 2025
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total operating revenues	$	3	$	—	$	934	$	( 25 )	$	912
Total costs and other	66		20		665		( 25 )		726

Non-operating (loss) income	( 23 )		( 3 )		2		—		( 24 )
(LOSS) INCOME BEFORE INCOME TAXES	( 86 )		( 23 )		271		—		162
Income tax provision	( 47 )		—		—		—		( 47 )
NET (LOSS) INCOME	$	( 133 )	$	( 23 )	$	271	$	—	$	115


	Three months ended March 31, 2024
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total operating revenues	$	6	$	—	$	457	$	( 9 )	$	454
Total costs and other	60		10		403		( 9 )		464
Gain on asset divestitures	—		—		6		—		6
Non-operating (loss) income	( 12 )		( 4 )		1		—		( 15 )
(LOSS) INCOME BEFORE INCOME TAXES	( 66 )		( 14 )		61		—		( 19 )
Income tax benefit	9		—		—		—		9
NET (LOSS) INCOME	$	( 57 )	$	( 14 )	$	61	$	—	$	( 10 )

NOTE 15 SUBSEQUENT EVENTS

Dividend

On May 5, 2025 , our Board of Directors declared a quarterly cash dividend of $ 0.3875 per share of common stock. The dividend is payable to shareholders of record at the close of business on May 30, 2025 and is expected to be paid on June 13, 2025 .

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

General

Business Environment and Industry Outlook

Commodity Prices

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

In early 2025, OPEC+ began unwinding prior voluntary production cuts, which added approximately 400,000 barrels per day to the global oil market. This substantial supply boost contributed to a decline in global oil prices during the three months ended March 31, 2025. Concurrently, in March and April 2025, the United States expanded tariff rates on imported goods based on both country of origin and material type. These expanded tariff rates, if sustained, could increase both the cost of oilfield goods and delivery lead times. Collectively, these policy changes—OPEC+'s production increase and the U.S. tariffs—are introducing significant volatility to the oil and gas sector. For more information on the impact of tariffs on our business, see Regulatory Updates .

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


	Three months ended
	March 31, 2025		December 31, 2024
Brent oil ($/Bbl)	$	74.92	$	73.97
WTI oil ($/Bbl)	$	71.42	$	70.27
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	$	3.65	$	2.79

Marketing Arrangements

In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025. Additionally, 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. Historically, we have sold a portion of our crude oil to these refineries. Assuming the Phillips 66 and Valero refineries both close, there will be six remaining major petroleum refineries in California, each of which have a refining capacity greater than 75,000 barrels per day. We expect California to collectively have 1.34 million barrels per day of remaining refining capacity, which is over four times the amount of crude oil produced in California in 2024. As a result of this and the considerable flexibility we have in marketing our production, we do not expect the closure of these refineries, should they occur, to affect our ability to market our crude oil production or to negatively impact our price realizations.

Regulatory Updates

Regulation of Exploration and Production Activities

Well Permitting

During the three months ended March 31, 2025, we received well permits for 53 workovers and 21 sidetracks. This reflects a continuing improvement in the rate of issuance by CalGEM of permits for workovers and sidetracks.

During the three months ended March 31, 2025, we continued to experience delays from CalGEM with respect to obtaining new well and deepening permits for our operations and did not receive any permits for these activities. However, during this period, CalGEM issued one new well permit for an oil and gas exploration well in Santa Barbara County to another operator in the state. This permit was issued outside of Kern County and in reliance on an environmental impact analysis other than the Kern County Environmental Impact Report (EIR) to comply with CEQA.

We currently hold sufficient permits to maintain our existing capital program through 2025. We also have the requisite number of permits in hand to run one active drilling rig throughout 2026.

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.

Evolving Federal Energy and Climate Policies

Since January 2025, the current administration has issued numerous Executive Orders that aim to increase oil production and decrease commodity prices. For example, a “national energy emergency” was declared in early January 2025, which gave the executive branch more power to expedite approvals for energy resource infrastructure (including oil and gas). Additionally, the administration issued the “Unleashing American Energy” Executive Order which incorporated numerous provisions aimed at unburdening and removing impediments to the development of various domestic energy resources, such as oil and gas. More recently, in March 2025, an Executive Order was signed that, among other matters, directed the U.S. Attorney General to investigate certain state laws that may adversely impact the development of energy resources, including state laws relating to climate change, environmental, social and governance initiatives, and funds collecting carbon penalties and/or taxes. We cannot predict what impact these Executive Orders or others may ultimately have on commodity prices, our operations or California laws and regulations relating to oil and gas, CCUS and climate change. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Refer to Results of Our Oil and Natural Gas Operations, Prices and Realizations below for information on our realized price.

In addition, in March and April 2025, the current administration implemented a substantial number of trade tariffs on all U.S. imports, including a new universal baseline reciprocal tariff of 10%, an additional country-specific reciprocal tariff for select trading partners and a tariff of 25% on imported steel and aluminum products. On April 10, 2025, the administration paused the additional country-specific tariffs for 90 days, until July 8, 2025, with the exception of the reciprocal tariff on China. While imports of oil, gas and refined products received exemptions from the tariffs, concerns that the measures could cause inflation, slow economic growth and intensify trade disputes have also placed downward pressure on oil prices. With negotiations and countermeasures still ongoing, the supply chain environment is fluid, and we expect price volatility to continue over the next few months. While we do not expect a significant and immediate impact on cost and availability of oilfield materials and supplies, these trade tariffs have the potential to significantly increase our operating and capital costs over the longer term.

Responsible Net Zero Goal

In May 2025, our Board of Directors adopted the following net zero emissions goal (Responsible Net Zero):

Our goal is to achieve at least an 80% reduction of absolute Scope 1 and 2 greenhouse gas emissions and neutralize the remaining Scope 1 and 2 emissions to achieve Net Zero by 2045. Our near-term ambition is to achieve a 20% reduction in the average carbon intensity of all CRC oil and gas production by 2035, thereby reducing our customers’ Scope 3 emissions. We are committed to responsibly producing energy in a manner consistent with the UN’s Sustainable Development Goals.

Our Responsible Net Zero goal is based on the following considerations:

• We use 2020 total Scope 1 and 2 GHG emissions (including those of Aera) as our baseline to measure progress towards our Responsible Net Zero goal. Our emissions are based on calculations reported to the California Air Resources Board (CARB).

• The term “neutralize” as it relates to Scope 1 GHG emissions refers to the planned use of either carbon offsets generated and claimed internally or carbon offsets purchased and claimed through the third party carbon market (including California’s Cap-and-Trade Program). For Scope 2 GHG emissions, the term “neutralize” refers to the use of contractual instruments such as renewable energy certificates or carbon offsets.

• The term “carbon offsets” refers to greenhouse gas emission reductions arising from third-party certified projects that remove, reduce, or avoid GHG emissions from the atmosphere.

• References to UN Sustainable Development Goals (UN SDGs) refer primarily to goals regarding income inequality, biodiversity, corruption, Scope 1 and 2 GHG emissions carbon intensity, fair labor and gender treatment. Operating a business consistent with UN SDGs is inherently a subjective determination regarding which UN SDGs to prioritize, how to weigh such matters against commercial considerations and to what extent a business activity promotes or is consistent with a given UN SDG.

• Future acquisitions and divestitures, as well as changes to methodology in accounting for carbon emissions or adjustments to historical carbon calculations as well as the use of third-party data or validation processes, could cause us to change our Responsible Net Zero goal.

• Assumptions, estimates, goals and similar statements and concepts regarding our Responsible Net Zero goal contain or assume forward looking statements within the meaning of federal securities laws and are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. For a discussion of these risks and uncertainties, please refer to the Risk Factors and Forward-Looking Statements described in our Annual Report on our most recent Form 10-K and any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K filed with the United States Securities and Exchange Commission.

Our Responsible Net Zero goal replaces our previously adopted Full Scope Net Zero goal. This change was primarily driven by the impact of the Aera Merger, which nearly doubled the size of our asset base and impacted the overall carbon intensity of our operations. The continuing lack of regulatory clarity around the measurement of Scope 3 GHG emissions (including the impact of carbon capture and sequestration in such calculations) also contributed to this change.

Statements of Operations Analysis

Consolidated Results of Operations

Three months ended March 31, 2025 compared to December 31, 2024

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


	Three months ended
	March 31, 2025		December 31, 2024

	(in millions)
Oil, natural gas and natural gas liquids sales	$	814	$	826
Net gain from commodity derivatives	6		(49)
Revenue from marketing of purchased commodities	64		59
Electricity revenue	22		39
Interest and other revenue	6		2
Total operating revenues	$	912	$	877

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 $814 million for the three months ended March 31, 2025, which is a decrease of $12 million compared to $826 million for the three months ended December 31, 2024.

The following table shows changes in oil, natural gas and natural gas liquids sales for the three months ended March 31, 2025 compared to the three months ended December 31, 2024:


	Oil		NGLs		Natural Gas		Total Operations

	(in millions)
Three months ended December 31, 2024	$	750	$	48	$	28	$	826
Changes in realized prices	8		2		5		15
Changes in production	(22)		—		(1)		(23)
Changes in intersegment revenues	—		—		(4)		(4)

Three months ended March 31, 2025	$	736	$	50	$	28	$	814

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

Net gain (loss) from commodity derivatives – We report gains and losses on our derivative contracts related to our oil production and marketing activities in operating revenue. Net gain from commodity derivatives was $6 million for the three months ended March 31, 2025 compared to a net loss of $49 million for the three months ended December 31, 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:


	Three months ended
	March 31, 2025		December 31, 2024
	(in millions)
Non-cash commodity derivative gain (loss)	$	22	$	(51)
Net settlements and amortized premiums	(16)		2
Net gain (loss) from commodity derivatives	$	6	$	(49)

Electricity revenue — Electricity revenue decreased by $17 million to $22 million for the three months ended March 31, 2025 compared to $39 million for the three months ended December 31, 2024. This decrease was primarily a result of lower seasonal pricing.

The following table presents our consolidated operating and non-operating expenses and income for the three months ended March 31, 2025 and December 31, 2024.


	Three months ended
	March 31, 2025		December 31, 2024

	(in millions)
Operating expenses
Energy operating costs	$	103	$	94
Gas processing costs	4		4
Non-energy operating costs	209		225
General and administrative expenses	72		95
Depreciation, depletion and amortization	131		142
Asset impairment	—		1
Taxes other than on income	70		80

Costs related to marketing of purchased commodities	50		53
Electricity generation expenses	10		9
Transportation costs	20		21
Accretion expense	29		31
Net (gain) loss on natural gas purchase derivatives	(6)		19

Measurement period adjustments	1		(12)
Other operating expenses, net	33		51
Total operating expenses	726		813
Gain on asset divestitures	—		4
Operating income	186		68

Non-operating (expenses) income

Interest and debt expense	(27)		(28)
Loss on early extinguishment of debt	(1)		—
Loss from investment in unconsolidated subsidiaries	(1)		(1)
Other non-operating income	5		2
Income before income taxes	162		41
Income tax provision	(47)		(8)
Net income	$	115	$	33

Energy operating costs consist of purchased natural gas used to generate electricity for our operations and steam for our steamfloods, purchased electricity and internal costs to generate electricity used in our operations. 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. There is no internal allocation of the costs to produce steam from the power plant 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 March 31, 2025 were $103 million, which was an increase of $9 million from $94 million for the three months ended December 31, 2024. This increase was primarily due to higher natural gas prices. We reduced the volume of natural gas used in our steamflood operations, resulting in a savings of $3 million in each of the three months ended March 31, 2025 and December 31, 2024. For more information on natural gas market prices, see Prices and Realizations below.

Non-energy operating costs — Non-energy operating costs for the three months ended March 31, 2025 were $209 million, which was a decrease of $16 million from $225 million for the three months ended December 31, 2024. The decrease was predominately a result of $7 million related to lower downhole maintenance, surface maintenance, and workover activity in addition to more favorable vendor pricing for the three months ended March 31, 2025 compared to the three months ended December 31, 2024.

General and administrative expenses — General and administrative (G&A) expenses were $72 million for the three months ended March 31, 2025 compared to $95 million for the three months ended December 31, 2024, which was a decrease of $23 million. The decrease was primarily a result of lower compensation-related expenses including stock-based compensation, bonus and retention awards and workforce reductions following the Aera Merger. See Liquidity and Capital Resources, Aera Integration below for additional information.

Compensation expense related to our bonus program decreased by $8 million for the three months ended March 31, 2025 compared to the three months ended December 31, 2024. This decrease was due to $4 million related to one-time retention awards granted in connection with the Aera Merger and $4 million related to the timing of the annual bonus accruals.

Cash-settled stock-based compensation expense decreased by $7 million primarily resulting from a lower expected payout on our incentive awards primarily due to a decline in our stock price at March 31, 2025 compared to December 31, 2024. Changes in our stock price introduce volatility in our results of operations because we pay cash-settled incentive awards based on our stock price on the vesting date and accounting rules require that we adjust our obligation for unvested awards to the amount that would be paid using our stock price at the end of each reporting period. Consequently, any future increases in our stock price will result in additional cash-settled stock-based compensation expense. Equity-settled stock-based compensation awards are not similarly adjusted for changes in our stock price.

The non-cash portion of general and administrative expenses, comprised of equity-settled stock-based compensation, was approximately $6 million for both the three months ended March 31, 2025 and December 31, 2024.

Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) for the three months ended March 31, 2025 was $131 million compared to $142 million during the three months ended December 31, 2024. The decrease of $11 million was primarily the result of adjustments to the DD&A rate based on reserve estimates and fair value adjustments to the Aera assets in the three months ended March 31, 2025. See Part I, Item 1 – Financial Statements, Note 2 Aera Merger for information on the Aera assets and the purchase price allocation.

Taxes other than on income — Taxes other than on income for the three months ended March 31, 2025 were $70 million, which is a decrease of $10 million from $80 million for the three months ended December 31, 2024. This decrease was due to lower greenhouse gas expense.

Net (gain) loss on natural gas purchased derivatives — Net gain from derivatives related to our purchase of natural gas was $6 million for the three months ended March 31, 2025 compared to a net loss of $19 million for the three months ended December 31, 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:


	Three months ended
	March 31, 2025		December 31, 2024
	(in millions)
Non-cash (gain) loss on natural gas purchase derivatives	$	(18)	$	5
Settlements	12		14
Net (gain) loss on natural gas purchase derivatives	$	(6)	$	19

Measurement period adjustments — Measurement period adjustments relate to the initial accounting for assets acquired and liabilities assumed in the Aera Merger. The adjustments during the three months ended March 31, 2025 included adjustments to depreciation, depletion and amortization expense resulting from changes to the initial purchase price allocation. The adjustments during the three months ended December 31, 2024 related to accretion expense related to asset retirement obligations and depreciation, depletion and amortization expense resulting from changes to the initial purchase price allocation.

Other operating expenses, net — Other operating expenses, net decreased $18 million to $33 million for the three months ended March 31, 2025 compared to $51 million for the three months ended December 31, 2024. For the three months ended March 31, 2025 and December 31, 2024, other operating expenses, net includes the following:


	Three months ended
	March 31, 2025		December 31, 2024
	(in millions)
Carbon management business expense	$	18	$	20
Aera transaction and integration costs	3		1
Energy costs due to downtime at Elk Hills power plant	—		6
Severance	2		2

Front-end engineering design studies	3		3
Write-off of unsuccessful capital workovers	—		7
All other	7		12
	$	33	$	51

Income taxes – The income tax provision for the three months ended March 31, 2025 was $47 million (representing an effective tax rate of 29%), compared to a provision of $8 million (representing an effective tax rate of 20%) for the three months ended December 31, 2024. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes for additional information on our effective tax rate.

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

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 March 31, 2025 or December 31, 2024.


	Three months ended
	March 31, 2025		December 31, 2024
	(in millions, except as otherwise stated)

Production and segment financial data
Net production sold (MBoe/d)	141		141
Segment total operating revenue	$	830	$	838
Segment profit	$	266	$	268

Items affecting comparability:

Net gain on asset divestitures (a)	$	—	$	4

Key operating expenses per Boe
Operating costs	$	25.60	$	25.35
Operating costs, after hedges	$	26.55	$	26.40
Segment general and administrative expenses (b)	$	0.95	$	0.69
Segment depreciation, depletion and amortization (c)	$	9.96	$	9.94
Segment taxes other than on income	$	4.66	$	5.39

(a) Gain on asset divestitures for the three months ended December 31, 2024 related to the sale of our Ventura assets.

(b) Excludes unallocated general and administrative expenses.

Production, Prices, and Realizations

Net Production Sold

The following table sets forth our average net production of oil, NGLs and natural gas sold per day in each of the California oil and natural gas basins in which we operate for the periods presented. 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
	March 31, 2025	December 31, 2024
Oil (MBbl/d)
San Joaquin Basin	84	86
Los Angeles Basin	18	17
Other Basins	9	9

Total	111	112
NGLs (MBbl/d)
San Joaquin Basin	10	10



Total	10	10
Natural gas (MMcf/d)
San Joaquin Basin	101	98
Los Angeles Basin	1	1
Sacramento Basin	12	13
Other Basins	3	3
Total	117	115

Total Net Production Sold (MBoe/d)	141	141

Total average net production sold remained unchanged at 141 MBoe/d for the three months ended March 31, 2025 and December 31, 2024. Our PSCs, which are described below, positively impacted our net oil production by 1 MBoe/d in the three months ended March 31, 2025 compared to the three months ended December 31, 2024.

Production-Sharing Contracts (PSCs)

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts that are in effect through the economic life of the assets. The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs.

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 table sets forth the average realized prices and price realizations on the commodities we sell as a percentage of average Brent, WTI and NYMEX indexes for our oil and natural gas operations for the periods presented:


	Three months ended
	March 31, 2025			December 31, 2024
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	74.92		$	73.97

Realized price without derivative settlements	$	73.57	98%	$	72.82	98%
Derivative settlements	(1.56)			0.18
Realized price with derivative settlements	$	72.01	96%	$	73.00	99%

WTI	$	71.42		$	70.27

Realized price without derivative settlements	$	73.57	103%	$	72.82	104%
Realized price with derivative settlements	$	72.01	101%	$	73.00	104%

Natural Gas Liquids ($ per Bbl)
Realized price (% of Brent)	$	54.64	73%	$	52.62	71%
Realized price (% of WTI)	$	54.64	77%	$	52.62	75%

Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	3.65		$	2.79

Realized price ($/Mcf)	$	4.12	113%	$	3.65	131%

Oil — Brent prices were slightly higher for the three months ended March 31, 2025 compared to the three months ended December 31, 2024. The increase in Brent prices is due to a combination of early-quarter OPEC+ inaction in terms of returning barrels to the market and various geopolitical factors.

NGLs — Prices for natural gas liquids during the three months ended March 31, 2025 increased compared to the three months ended December 31, 2024, reflecting traditional seasonality and moving in tandem with crude oil prices.

Natural Gas — Natural gas prices increased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 driven by colder-than-anticipated winter temperatures across most of the United States, resulting in strong demand and large storage withdrawals bringing storage inventories in line with historical norms.

Results of Our Carbon Management Segment

Our carbon management segment, which we refer to as Carbon TerraVault, primarily pursues the development of carbon capture and sequestration 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, and did not have any revenue for the three months ended March 31, 2025 or December 31, 2024. We define carbon management expense to be our direct operating costs to run our carbon management segment.

The following tables include results for our carbon management segment for the three months ended March 31, 2025 and December 31, 2024.


	Three months ended
	March 31, 2025		December 31, 2024
	(in millions)
Segment loss	$	( 25 )	$	(31)

Items affecting comparability:
Asset impairments (a)	$	—	$	1

(a) Asset impairment for the three months ended December 31, 2024 related to land acquired for our carbon management activities. The table above excludes asset impairments that were not related to the carbon management segment.


	Three months ended
	March 31, 2025		December 31, 2024
	(in millions)
Carbon management expenses	$	18	$	20
Segment general and administrative expenses	3		5
Loss from investment in the Carbon TerraVault JV	$	1	$	2

Carbon management expenses decreased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 as a result of lower advocacy and operating lease cost related to easements, partially offset by costs related to increases in front-end engineering design and other feasibility work during the three months ended March 31, 2025.

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 months ended March 31, 2025 were for debt reduction, repurchases of our common stock, payment of fixed dividends and capital investments.

The following table summarizes our liquidity:



	March 31, 2025
	(in millions)
Available cash and cash equivalents (a)	$	199
Revolving Credit Facility:
Borrowing capacity	1,150

Outstanding letters of credit	(167)
Availability	$	983

Liquidity	$	1,182

(a) Excludes restricted cash of $15 million.

At current commodity prices and based upon our planned 2025 capital program described below, we expect to generate operating cash flow to support and invest in our core assets and preserve financial flexibility. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or stock buybacks to the extent permitted under our Revolving Credit Facility and the indentures for our 7.125% senior notes due 2026 (2026 Senior Notes) and our 8.25% senior notes due 2029 (2029 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

The borrowing base under our Revolving Credit Facility is redetermined semi-annually and was reaffirmed at $1.5 billion on April 4, 2025. The borrowing base takes into account the estimated value of our proved reserves, total indebtedness and other relevant factors consistent with customary reserves-based lending criteria. The amount we are able to borrow under our Revolving Credit Facility is limited to the amount of the commitments from our lenders, which is currently $1.15 billion. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt in our 2024 Annual Report for additional information on the Revolving Credit Facility and related amendments.

2026 Senior Note Redemptions

In February 2025, we redeemed $123 million of our 2026 Senior Notes at 100% of the principal amount of such notes, resulting in a loss on early extinguishment of debt in the amount of $1 million for the write-off of unamortized debt issuance costs.

Share Repurchase Program

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.35 billion of our common stock through December 31, 2025. As of March 31, 2025, the aggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $457 million, excluding commissions and excise taxes on repurchases. 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 contracts otherwise in compliance with Rule 10b-18, subject to market conditions and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend or discontinue authorization of the program at any time. The following is a summary of our share repurchases, which are held as treasury stock, for the periods presented:


	Total Number of Shares Purchased	Total Value of Shares Purchased		Average Price Paid per Share
	(number of shares)	(in millions)		($ per share)
Three months ended March 31, 2024	1,065,764	$	58	$	53.26
Three months ended March 31, 2025	2,271,919	101		$	44.00




Inception of Program (May 2021) through March 31, 2025	20,785,182	897		$	42.95

Note: The total value of shares purchased includes approximately $1 million in both the three months ended March 31, 2025 and 2024 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented. Total commissions and excise taxes paid since the inception of the program total $4 million.

Dividends

We paid the following fixed cash dividends in each of the periods presented.


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

Three months ended March 31, 2025	$	35	$	0.3875




Three months ended March 31, 2024	$	21	$	0.31

In addition to dividends declared, we paid $1 million and $4 million of dividend equivalents related to stock-based compensation awards which were settled in the three months ended March 31, 2025 and 2024, respectively . The declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. Since the adoption of our dividend policy in 2021, we have returned $302 million to shareholders through dividends (excluding dividend equivalents).

On May 5, 2025 , our Board of Directors declared a quarterly cash dividend of $0.3875 per share of common stock. The dividend is payable to shareholders of record at the close of business on May 30, 2025 and is expected to be paid on June 13, 2025 .

2025 Capital Program

Our capital program is dynamic in response to commodity price volatility and permit availability while focusing on oil production and maximizing our free cash flow. Our capital investment for the three months ended March 31, 2025 was $55 million. We expect our 2025 capital program to remain at a range between $285 million and $335 million. Of this amount, $250 million to $280 million is related to our oil and natural gas segment, $20 million to $30 million is for our carbon management segment and $15 million to $25 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 expect to run a two rig program in the second half of 2025 using existing permits in hand. 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 spend by segment.

Derivatives

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

Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended March 31, 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 March 31, 2025 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2024 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

Aera Integration

In August 2024 and March 2025, management undertook a reduction in force as part of the integration process following the Aera Merger. After employee transition periods, the reduction in the combined employee headcount will be approximately 12%. We initiated this workforce reduction to align the size and composition of our workforce with expected future operating and capital plans. Employee severance and related costs are included in other operating expenses, net on our condensed consolidated statement of operations. We also amended Aera's pension and postretirement benefit plans in August 2024 resulting in a reduction of service cost, which is reported as a component of general and administrative expenses.

We anticipate that the integration of our workforce and amendment of our benefit plans will result in approximately $80 million of annual savings, of which approximately $50 million relates to general and administrative expenses and approximately $30 million relates to non-energy operating costs. In August 2024, we also reduced the number of our contractors resulting in approximately $5 million of annual savings.

Cash Flow Analysis

Cash flows from operating activities — For the three months ended March 31, 2025, our operating cash flow increased by $99 million to $186 million from $87 million in the same period in 2024. This increase in operating cash flow was primarily driven by the Aera Merger on July 1, 2024.

With the acquisition of Aera's assets, oil production during the three months ended March 31, 2025 as compared to the same periods in 2024 increased 63 MBbl/d from 48 MBbl/d to 111 MBbl/d. 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 $5.16 per barrel to $72.01 in the three months ended March 31, 2025 from $77.17 in the same prior year period. Further, as a result of the Aera Merger, we experienced higher operating costs, production taxes and greenhouse gas taxes during the three months ended March 31, 2025 as compared to the same prior year period in addition to one-time transaction and integration costs were incurred in 2025.

During the three months ended March 31, 2024, scheduled plant 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:


	Three months ended March 31,
		2025		2024

		(in millions)
Capital investments		$	(55)	$	(54)
Changes in accrued capital investments		(21)		(4)
Proceeds from asset divestitures		—		10




Other, net		(3)		(1)
Net cash used in investing activities		$	(79)	$	(49)

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


	Three months ended March 31,
		2025		2024

		(in millions)





Repurchases of common stock (a)		$	(101)	$	(58)
Common stock dividends		(35)		(21)
Dividend equivalents on equity-settled awards		(1)		(4)

Issuance of common stock		6		1
Bridge loan commitment costs		—		(8)
Debt redemption		(123)		—


Shares cancelled for taxes		(11)		(41)
Net cash provided by (used in) financing activities		$	(265)	$	(131)

(a) The total value of shares purchased reported on our statement of cash flows includes approximately $1 million in both the three months ended March 31, 2025 and 2024 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented.

For the three months ended March 31, 2025, our cash flow used in financing activities increased by $134 million to $265 million from $131 million in the same period in 2024. This increase in cash flow used in financing activities was primarily driven by $123 million used to redeem a portion of the 2026 Senior Notes in February 2025. Additionally, $101 million was used for the repurchases of common stock in the three months ended March 31, 2025 as compared to $58 million in the three months ended March 31, 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 March 31, 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 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 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; 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 months ended March 31, 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 March 31, 2025, we had a net liability of $29 million for our commodity derivative positions which are carried at fair value. For more information on our derivative positions as of March 31, 2025 , refer to Part I, Item 1 – Financial Statements, Note 6 Derivatives.

As of March 31, 2025, we have hedges on approximately 70% of our expected oil production for the remainder of 2025 at a weighted average floor price of $67.07. As of March 31, 2025, our hedges for purchased natural gas approximate 70% of our expected fuel use in oil and natural gas operations for the remainder of 2025 at a fixed price of $3.41.

Counterparty Credit Risk

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

As of March 31, 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 March 31, 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 March 31, 2025 . Our 2026 Senior Notes bear interest at a fixed rate of 7.125% per annum. Our 2029 Senior Notes bear interest at a fixed rate of 8.250% per annum.

Item 4 Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer supervised and participated in management's evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 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 March 31, 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 March 31, 2025.

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds

Aera Merger

In connection with the Aera Merger, on February 24, 2025, we issued 107,265 shares of our common stock, par value $0.01 per share to the former Aera owners (Sellers). This deferred consideration is related to pre-effective date and restructuring income taxes of the Sellers. The share issuance was made in reliance on an exemption from the registration requirements pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended, and Rule 506 of Regulation D promulgated thereunder, since the share issuance does not involve any public offering.

Share Repurchases

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

Our share repurchase activity for the three months ended March 31, 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)
January 1, 2025 - January 31, 2025	336,665	$	52.74	336,665	$	—
February 1, 2025 - February 28, 2025	—	$	—	—	—
March 1, 2025 - March 31, 2025	1,935,254	$	42.47	1,935,254	—
Total	2,271,919	$	44.00	2,271,919	$	—

(a) The total value of shares that may yet be purchased under the Share Repurchase Program totaled $457 million as of March 31, 2025.

Item 5 Other Disclosures

Rule 10b5-1 Trading Arrangements

During the three months ended March 31, 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


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).

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

SIGNATURES

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


			CALIFORNIA RESOURCES CORPORATION


DATE:	May 7, 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

3.1 Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 to Registrants 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 Registrants Registration Statement on Form 8-A filed October 27, 2020 and incorporated herein by reference). 31.1* Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2* Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1* Certifications of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

CRC 10-Q Quarter ended March 31, 2025

Exhibits