crc-20260331

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, 2026

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ___________

Commission file number 001-36478

California Resources Corporation

(Exact name of registrant as specified in its charter)


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

1 World Trade Center, Suite 1500

Long Beach, California 90831

(Address of principal executive offices) (Zip Code)

(888) 848-4754

(Registrant’s telephone number, including area code)

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


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

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

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

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

Large Accelerated Filer

☑

Accelerated Filer

☐

Non-Accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

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

Indicate 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, 2026 was 88,794,901.

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 (Loss) Income	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	30
	General	30
	Business Environment and Industry Outlook	30
	Regulatory Updates	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
	Lawsuits, Claims, Commitments and Contingencies	42
	Critical Accounting Estimates and Significant Accounting and Disclosure Changes	42
	Forward-Looking Statements	43
Item 3	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4	Controls and Procedures	45

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

GLOSSARY AND SELECTED ABBREVIATIONS

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

•AB - Assembly Bill

•ABR - Alternate base rate.

•Aera - Aera Energy LLC.

•Aera Merger - The transactions contemplated by the definitive agreement and plan of merger entered into on February 7, 2024 to obtain all the ownership interests in Aera in an all-stock transaction.

•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.

•Berry - Berry Corporation (bry).

•Berry Merger - The transactions contemplated by the definitive agreement and plan of merger entered into on September 14, 2025 to combine with Berry in an all-stock transaction.

•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.

•CO2 - Carbon dioxide.

•DAC - Direct air capture.

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

•EOR - Enhanced oil recovery.

•EPA - United States Environmental Protection Agency.

•ESG - Environmental, social and governance.

•E&P - Exploration and production.

•GAAP - United States Generally Accepted Accounting Principles.

•G&A - General and administrative expenses.

•GHG - Greenhouse gases.

•JV - Joint venture.

•KMTPA - Thousand metric tons per annum.

•LCFS - Low Carbon Fuel Standard.

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

•MBbl/d - One thousand barrels per day.

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

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

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

•MHp - One thousand horsepower.

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

•MMBoe - One million barrels of oil equivalent.

•MMBtu - One million British thermal units.

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

•MMT - Million metric tons.

•MMTPA - Million metric tons per annum.

•MW - Megawatts of power.

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

•NYMEX - The New York Mercantile Exchange.

•OCTG - Oil country tubular goods.

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

•OPEC - Organization of the Petroleum Exporting Countries.

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

•PHMSA - Pipeline and Hazardous Materials Safety Administration.

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

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

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

•PSCs - Production-sharing contracts.

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

•Responsible Net Zero - Refers to our net zero emissions goal adopted by our Board of Directors in May 2025 consisting of achieving at least an 80% reduction of absolute Scope 1 and 2 GHG emissions and neutralizing the remaining Scope 1 and 2 emissions to achieve Net Zero by 2045.

•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 1Financial Statements

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of March 31, 2026 and December 31, 2025

(in millions, except share data)


	March 31,		December 31,
	2026		2025
	(unaudited)		(audited)
CURRENT ASSETS
Cash and cash equivalents	$	40	$	132
Trade receivables	454		333
Inventory	107		106

Receivable from affiliate	7		14
Other current assets, net	180		353
Total current assets	788		938
PROPERTY, PLANT AND EQUIPMENT	7,657		7,523
Accumulated depreciation, depletion and amortization	(1,753)		(1,618)
Total property, plant and equipment, net	5,904		5,905
INVESTMENT IN UNCONSOLIDATED SUBSIDIARIES	102		111
DEFERRED TAX ASSETS	81		76
OTHER NONCURRENT ASSETS	274		373
TOTAL ASSETS	$	7,149	$	7,403


CURRENT LIABILITIES



Accounts payable	472		452

Fair value of commodity derivative contracts	421		42
Accrued liabilities	548		556

Total current liabilities	1,441		1,050
NONCURRENT LIABILITIES
Long-term debt, net	1,310		1,283
Fair value of derivative contracts	169		17
Asset retirement obligations	906		913
Deferred tax liabilities	108		154
Other long-term liabilities	297		312



STOCKHOLDERS' EQUITY
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at March 31, 2026 and December 31, 2025	—		—
Common stock (200,000,000 shares authorized at $0.01 par value) (110,905,146 and 110,645,691 shares issued; 88,794,901 and 88,754,165 shares outstanding at March 31, 2026 and December 31, 2025)	1		1
Treasury stock (22,110,245 shares held at cost at March 31, 2026 and 21,891,526 shares held at cost at December 31, 2025)	(954)		(944)
Additional paid-in capital	2,626		2,625
Retained earnings	1,159		1,905
Accumulated other comprehensive income	86		87


Total stockholders' equity	2,918		3,674
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	7,149	$	7,403

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations (unaudited)

For the three months ended March 31, 2026 and 2025

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


	Three months ended March 31,
	2026		2025
REVENUES
Oil, natural gas and natural gas liquids sales	$	905	$	814
Net (loss) gain from commodity sales derivatives	(848)		6
Revenue from marketing of purchased commodities	41		64
Electricity revenue	11		22
Other revenue	10		6
Total operating revenues	119		912

OPERATING EXPENSES
Operating costs	365		316
General and administrative expenses	106		72
Depreciation, depletion and amortization	133		131


Taxes other than on income	67		70

Costs related to marketing of purchased commodities	23		50
Electricity generation expenses	5		10
Transportation costs	26		20
Accretion expense	27		29
Net loss (gain) from natural gas purchase derivatives	24		(6)
Measurement period adjustments, net	—		1
Other operating expenses, net	54		33
Total operating expenses	830		726


OPERATING (LOSS) INCOME	(711)		186

NON-OPERATING (EXPENSES) INCOME

Interest and debt expense, net	(29)		(27)
Loss on early extinguishment of debt	(21)		(1)
Equity loss from unconsolidated subsidiaries	(2)		(1)
Other non-operating income, net	3		5
(LOSS) INCOME BEFORE INCOME TAXES	(760)		162
Income tax benefit (provision)	49		(47)
NET (LOSS) INCOME	$	(711)	$	115






Net (loss) income per share
Basic	$	(8.02)	$	1.27
Diluted	$	(8.02)	$	1.26

Weighted-average common shares outstanding
Basic	88.7		90.6
Diluted	88.7		91.2

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

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

For the three months ended March 31, 2026 and 2025

(in millions)


	Three months ended March 31,
	2026		2025
Net (loss) income	$	(711)	$	115
Other comprehensive income (loss)(a):


Amortization of prior service cost credit included in net periodic benefit cost, net of tax	(1)		(2)

Comprehensive (loss) income	$	(712)	$	113

(a) Tax effects of the amortization of prior service cost credit were insignificant for the three months ended March 31, 2026 and 2025.

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, 2026 and 2025

(in millions)


	Three months ended March 31, 2026
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, December 31, 2025	$	1	$	(944)	$	2,625	$	1,905	$	87	$	3,674
Net loss	—		—		—		(711)		—		(711)

Share-based compensation	—		—		12		—		—		12


Repurchases of common stock	—		(10)		—		—		—		(10)



Cash dividend	—		—		—		(36)		—		(36)
Shares cancelled for taxes	—		—		(12)		—		—		(12)
Other comprehensive loss, net of tax	—		—		—		—		(1)		(1)
Other	—		—		1		1		—		2
Balance, March 31, 2026	$	1	$	(954)	$	2,626	$	1,159	$	86	$	2,918


	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	—		—		—		(36)		—		(36)
Shares cancelled for taxes	—		—		(11)		—		—		(11)
Other comprehensive loss, net of tax	—		—		—		—		(2)		(2)
Other	—		—		1		—		—		1
Balance, March 31, 2025	$	1	$	(897)	$	2,580	$	1,759	$	73	$	3,516

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, 2026 and 2025

(in millions)


	Three months ended March 31,
	2026		2025
CASH FLOW FROM OPERATING ACTIVITIES
Net (loss) income	$	(711)	$	115
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	133		131

Deferred income tax (benefit) provision	(50)		35

Net loss (gain) from commodity derivatives	872		(12)
Net settlements from commodity derivatives	(68)		(28)
Net loss on early extinguishment of debt	21		1




Other non-cash charges to income, net	50		10
Net changes in operating assets and liabilities	(148)		(66)
Net cash provided by operating activities	99		186

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(131)		(55)
Changes in accrued capital investments	(10)		(21)


Acquisitions	(2)		—
Distribution from unconsolidated subsidiary	10		—


Other, net	(3)		(3)
Net cash used in investing activities	(136)		(79)

CASH FLOW FROM FINANCING ACTIVITIES




Proceeds from Revolving Credit Facility	245		—
Repayments of Revolving Credit Facility	(220)		—
Proceeds from 2034 Senior Notes, net	347		—
Repurchases of common stock	(10)		(101)
Common stock dividends	(36)		(35)
Dividend equivalents on equity-settled awards	(2)		(1)





Issuance of common stock	—		6




Shares cancelled for taxes	(12)		(11)

Debt redemption	(367)		(123)

Net cash used in financing activities	(55)		(265)
Decrease in cash and cash equivalents	(92)		(158)
Cash and cash equivalents—beginning of period	132		372
Cash and cash equivalents—end of period	$	40	$	214

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements (Unaudited)

March 31, 2026

NOTE 1 BASIS OF PRESENTATION

We are an independent energy and carbon management company advancing the 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 December 18, 2025, pursuant to the Agreement and Plan of Merger, dated as of September 14, 2025 (the Berry Merger Agreement), we obtained all of the ownership interests in Berry Corporation (bry) (Berry) in an all-stock transaction (Berry Merger). Our consolidated results of operations for the three months ended March 31, 2026 include the full-quarter results of Berry, while the comparable prior-year period does not include any results of Berry. Accordingly, the Berry Merger significantly impacts the comparability of our financial results for the three months ended March 31, 2026 as compared to the same period in 2025. See Note 2, Business Combination, for additional information.

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 initially 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 was 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, 2025 (2025 Annual Report).

The carrying amounts of cash, cash equivalents and on-balance sheet financial instruments, other than debt, approximate fair value. Refer to Note 4 Debt for the fair value of our debt.

Recently Issued but not Adopted Accounting and Disclosure Changes

In November 2024, the FASB issued new disclosure requirements to enhance disclosure of certain costs and expenses. The rules are effective for fiscal years beginning after December 15, 2026 and interim periods beginning after December 15, 2027, early adoption is permitted. We expect that the adoption of these rules will impact our disclosures and have no impact to our results of operations, cash flows and financial condition.

NOTE 2 BUSINESS COMBINATION

Berry Merger

On September 14, 2025, we entered into an agreement to combine with Berry in the Berry Merger. Berry was an independent upstream energy company that explored for and produced oil and natural gas in California, primarily in the San Joaquin basin, and in the Uinta basin in Utah. Berry also provided well servicing and abandonment services, which is included in our oil and natural gas segment. The Berry Merger added high quality, oil-weighted, mostly conventional proved developed reserves and sustainable cash flows to our operations.

Pursuant to the Berry Merger Agreement, on the effective date of the merger, December 18, 2025, we issued 5,572,115 shares of our common stock, which was calculated as 0.0718 shares of our common stock for each outstanding share of Berry stock as of December 17, 2025. As of December 18, 2025, and immediately following the closing of the Berry Merger, the former Berry stockholders owned 6% of CRC. We paid cash or issued replacement equity awards in settlement of certain Berry restricted and performance units. Upon closing of the Berry Merger, Berry's outstanding debt was repaid and the underlying credit agreements were terminated. We repaid a significant portion of this indebtedness with proceeds from our 2034 Senior Notes. For more information on the 2034 Senior Notes, refer to Note 4 Debt.

At the date of this filing, our assessment of the fair value of assets acquired and liabilities assumed remains preliminary. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, final appraisals of Berry's property, plant and equipment, evaluation of Berry's materials and supplies inventory, valuation of certain assets and liabilities, determination of Berry'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 Berry Merger closing date and adjustments may be made to the provisional amounts recorded as of March 31, 2026.

We 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	5,572,115
Common stock per share fair value on December 17, 2025	$	45.49
Fair value of share consideration	$	253
Settlement of Berry debt	449
Stock-based compensation	7
Total consideration	$	709

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


	Preliminary Purchase Price as of December 31, 2025		Adjustments		Preliminary Purchase Price as of March 31, 2026
	(in millions)		(in millions)		(in millions)
Assets Acquired
Cash	$	12	$	—	$	12
Accounts receivable	87		1		88
Inventories	6		—		6
Other current assets	29		—		29
Property, plant and equipment	659		(3)		656
Fair value of derivative contracts	109		—		109
Deferred tax asset	121		1		122
Other noncurrent assets	4		—		4
Total Assets Acquired	1,027		(1)		1,026

Liabilities Assumed
Accounts payable	$	(62)	$	—	$	(62)
Accrued liabilities	(50)		1		(49)
Asset retirement obligations	(151)		—		(151)
Fair value of derivative contracts	(21)		—		(21)


Other long-term liabilities	(34)		—		(34)
Total Liabilities Assumed	(318)		1		(317)
Net Assets Acquired	$	709	$	—	$	709

Supplemental Unaudited Pro Forma Financial Information

The following supplemental unaudited pro forma financial information presents the total operating revenue, net income and earnings per share for the three months ended March 31, 2025 as if the Berry Merger had occurred on January 1, 2025.


	Three Months Ended March 31,
	2025

	(in millions, except per share amounts)
Total operating revenue	$	1,087
Net income	$	6

EPS
Basic	$	0.06
Diluted	$	0.06

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 Berry Merger been completed on January 1, 2025, 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, 2025 is a result of combining our three months statements of operations with Berry's pre-merger results for the three months ended March 31, 2025 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 Berry 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 Berry Merger. Management believes the estimates and assumptions are reasonable, and the relative effects of the Berry Merger are properly reflected. Future results may vary significantly from the results reflected in the following pro forma information.

NOTE 3 INVESTMENT IN UNCONSOLIDATED SUBSIDIARIES AND RELATED PARTY TRANSACTIONS

As of March 31, 2026 and December 31, 2025, our investments in unconsolidated subsidiaries was $102 million and $111 million, respectively. The following tables present changes to our investment in unconsolidated subsidiaries for the periods presented:


	Carbon TerraVault JV		Midway Sunset Cogeneration Company
	(in millions)		(in millions)
Investment, December 31, 2025	$	57	$	54



Net loss	(1)		(1)
Contributions (distributions)	3		(10)
Investment, March 31, 2026	$	59	$	43

Investment, December 31, 2024	$	27	$	59
Net loss	(1)		—
Contributions	4		—
Adjustment to the preliminary purchase price allocation	—		(7)
Investment, March 31, 2025	$	30	$	52

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 CO2 into the 26R reservoir in our Elk Hills field for permanent CO2 storage (26R reservoir). Brookfield has contributed $92 million to date. The remaining amount of Brookfield's initial investment is based on the permitted storage capacity, subject to certain contractual adjustments. This remaining amount will be contributed to the joint venture upon entering into contracts for the injection of specified volumes with respect to the 26R reservoir.

Although we determined that the Carbon TerraVault JV is a variable interest entity (VIE), we share decision-making power with Brookfield on all matters that most significantly impact the economic performance of the joint venture. Therefore, we account for our investment in the Carbon TerraVault JV under the equity method of accounting. Transactions between us and the Carbon TerraVault JV are related party transactions.

Because the parties have certain put and call rights (repurchase features) with respect to the 26R reservoir if certain milestones are not met, the initial investment by Brookfield is reflected as a contingent liability included in other long-term liabilities on our condensed consolidated balance sheets. The contingent liability was $120 million at March 31, 2026 and $117 million at December 31, 2025, inclusive of interest. The amount payable to Brookfield under the put and call rights, if exercised, includes additional capital contributions made by Brookfield to develop the 26R storage reservoir, inclusive of interest. This payment would differ from the contingent liability currently recognized because the contingent liability reported in other long-term liabilities on our condensed consolidated balance sheet relates solely to the initial investment by Brookfield and does not include capital contributions made for ongoing development activities of the 26R reservoir.

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



	March 31,		December 31,
	2026		2025

	(in millions)

Receivable from affiliate(a)	$	7	$	14
Other long-term liabilities(b)	$	120	$	117

(a)At March 31, 2026, the amount of $7 million includes the remaining $4 million of Brookfield's first and second installments of their initial investment which is available to us and $3 million related to the Master Service Agreement (MSA) and vendor reimbursements. At December 31, 2025, the amount of $14 million includes $8 million remaining of Brookfield's first and second installment of their initial investment which is available to us and $6 million related to the MSA and vendor reimbursements.

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

We recognized a loss of $1 million for both the three months ended March 31, 2026 and 2025 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 CO2. During the three months ended March 31, 2026 and 2025, we performed well abandonment work and sought reimbursement for an insignificant amount and $2 million, respectively, from the Carbon TerraVault JV. We recorded these reimbursements as a reduction to property, plant and equipment, net on our condensed consolidated balance sheets.

Midway Sunset Cogeneration Company

The Aera Merger led to our partial ownership of Midway Sunset Cogeneration Company, which is a partnership designed to own, manage, and operate a cogeneration facility in Kern County, California. We hold a 50% interest in Midway Sunset Cogeneration Company and an affiliate of Middle River Power, LLC (MRP), holds a 50% interest. We determined that Midway Sunset Cogeneration Company is a voting interest entity, where we share decision-making power with MRP on all matters that most significantly impact the economic performance of Midway Sunset Cogeneration Company. Therefore, we account for our investment in Midway Sunset Cogeneration Company under the equity method of accounting. There are no significant transactions between us and Midway Sunset Cogeneration Company.

In the three months ended March 31, 2026, we received a distribution of $10 million from the Midway Sunset Cogeneration Company.

NOTE 4 DEBT

As of March 31, 2026 and December 31, 2025, our long-term debt consisted of the following:



	March 31,		December 31,
	2026		2025		Interest Rate	Maturity

	(in millions)

Revolving Credit Facility	$	25	$	—	SOFR plus 2.50%-3.50% ABR plus 1.50%-2.50%(a)	March 16, 2029


2029 Senior Notes	550		900		8.250%	June 15, 2029
2034 Senior Notes	750		400		7.000%	January 15, 2034
Principal amount	1,325		$	1,300
Unamortized debt discount and issuance costs	(18)		(19)
Unamortized premium	3		2


Long-term debt, net	$	1,310	$	1,283

(a)Refer to Note 15 Subsequent Events for more information on a recent amendment to the Revolving Credit Facility that reduced our interest rate pricing by 25 basis points and an additional 10 basis point incremental savings through the elimination of the SOFR credit spread adjustment.

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 $1.46 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, 2026, $184 million letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters. As of March 31, 2026, we had $1,251 million of availability on our Revolving Credit Facility after taking into account $184 million in letters of credit outstanding and a $25 million borrowing. Our borrowing base of $1.5 billion is redetermined semi-annually and was re-affirmed in April 2026 as part of our recent amendment. See Note 15 Subsequent Events for more information on a recent amendment to our Revolving Credit Facility.

Fair Value

As shown in the table below, we estimate the fair value of our fixed rate 2029 Senior Notes and 2034 Senior Notes based on known prices from market transactions (using Level 1 inputs on the fair value hierarchy).


	March 31,		December 31,
	2026		2025

	(in millions)
Variable rate debt	$	25	$	—
Fixed rate debt

2029 Senior Notes	576		943
2034 Senior Notes	756		394
Fair Value of Long-Term Debt	$	1,357	$	1,337

2034 Senior Notes and Follow-On Offering

On October 8, 2025 we completed a private offering of $400 million in an aggregate principal amount of 7.000% senior notes due 2034 (2034 Senior Notes). The terms of the 2034 Senior Notes are governed by the Indenture, dated as of October 8, 2025, by and among us, the guarantors and Wilmington Trust, National Association, as trustee, as amended and supplemented by the First Supplemental Indenture, dated as of January 16, 2026 (2034 Senior Notes Indenture).

On March 23, 2026, we completed a follow-on offering of an additional $350 million in aggregate principal of 2034 Senior Notes. The net proceeds from this offering of $347 million, after $2 million of debt premium and $5 million of debt issuance costs, were used to redeem a portion of our 8.250% senior unsecured notes due 2029 (2029 Senior Notes). The 2034 Senior Notes issued on March 23, 2026 are governed under the 2034 Senior Notes Indenture.

2029 Senior Notes Redemption

In March 2026, we redeemed $350 million in face value of our 2029 Senior Notes for $367 million, resulting in a loss on extinguishment of debt in the amount of $21 million, which includes a $17 million premium paid and $4 million write-off of unamortized debt issuance costs. Following the redemption, $550 million in principal amount of the 2029 Senior Notes remained outstanding.

Other

As of March 31, 2026, we were in compliance with all financial and other debt covenants under our Revolving Credit Facility, 2029 Senior Notes and 2034 Senior Notes.

NOTE 5 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

We are party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. We accrue reserves for currently outstanding lawsuits, claims and proceedings when we determine it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances for these items at March 31, 2026 and December 31, 2025 were not material to our condensed consolidated balance sheets as of such dates. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined.

In October 2020, Signal Hill Services, Inc. defaulted on its decommissioning obligations associated with two offshore platforms. The Bureau of Safety and Environmental Enforcement (BSEE) determined that former lessees, including our former parent, Occidental Petroleum Corporation (Oxy) with a 37.5% share, are responsible for decommissioning obligations associated with these offshore platforms. Oxy sold its interest in the platforms approximately 30 years ago and it is our understanding that Oxy has not had any connection to the operations since that time and was challenging BSEE's order. Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy. In September 2021, we accepted the indemnification claim from Oxy and are challenging the order from BSEE. In March 2024, we entered into a cost sharing agreement with former lessees to share in ongoing maintenance costs during the pendency of the challenge to the BSEE order. In September 2025, the parties amended the cost sharing agreement to include well abandonment work. As of March 31, 2026, we had a liability of approximately $18 million included in accrued liabilities in our condensed consolidated balance sheet related to this abandonment work. For the three months ended March 31, 2026, other operating expenses, net on our condensed consolidated statement of operations includes $10 million, for our ongoing share of maintenance costs and well abandonment work. We continue to challenge the BSEE order.

In 2023 and 2024, the California Geologic Energy Management Division (CalGEM) plugged and abandoned approximately 120 "orphaned" oil and gas wells located in Cat Canyon, Santa Barbara County, at an aggregate cost of approximately $25 million. A subsidiary of our predecessor entity sold these wells to the defunct operator prior to CRC's formation and are therefore in our chain of title. CalGEM is seeking to recover these costs from us due to our prior operatorship of the wells, and we are disputing these claims. In connection with this dispute, we were required to remit approximately $25 million to CalGEM under protest pending the outcome of this matter. We have filed a complaint against CalGEM to reclaim the $25 million that we paid in June 2025.

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 a portion of our 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, 2026 and 2025. 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 for our forecasted oil production as of March 31, 2026:


	Q2 2026		Q3 2026		Q4 2026		2027		2028
Sold Calls
Barrels per day	36,000		36,000		36,000		2,465		17,534
Weighted-average price per barrel	$	83.51	$	83.51	$	83.51	$	71.06	$	81.28

Purchased Puts
Barrels per day	36,000		36,000		36,000		2,465		17,534
Weighted-average price per barrel	$	61.11	$	61.11	$	61.11	$	61.01	$	62.74

Swaps
Barrels per day	44,487		42,869		41,703		69,610		7,285
Weighted-average price per barrel	$	68.52	$	68.20	$	67.98	$	65.69	$	66.98

At March 31, 2026, we also held the following swaps to hedge purchased natural gas used in our operations as shown in the table below.


	Q2 2026		Q3 2026		Q4 2026		2027		2028

SoCal Border
MMBtu per day	13,250		10,570		9,908		3,463		—
Weighted-average price per MMBtu	$	4.82	$	4.83	$	4.84	$	4.77	$	—

NWPL Rockies
MMBtu per day	91,750		91,750		91,750		88,254		11,475
Weighted-average price per MMBtu	$	3.77	$	3.76	$	4.17	$	4.00	$	3.51

In the three months ended March 31, 2026, we also had a limited number of derivative contracts related to our natural gas marketing activities that were intended to lock in locational price spreads. These derivative contracts were not significant to our results of operations or financial statements taken as a whole.

The outcomes of the derivative positions shown in the tables above are as follows:

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

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

•Swaps – with respect to swaps for crude oil, we make settlement payments for prices above the indicated weighted-average price per barrel and receive settlement payments for prices below the indicated weighted-average price per barrel. With respect to swaps for purchased natural gas, we receive settlement payments for prices above the indicated weighted-average price per MMBtu and we make settlement payments for prices below the weighted-average price per MMBtu.

Fair Value of Derivatives

Derivative instruments not designated as hedging instruments are required to be recorded on the balance sheet at fair value. We report gains and losses on our derivative contracts related to our oil production and our marketing activities in operating revenue on our consolidated statements of operations as shown in the table below:


	Three months ended March 31,
	2026		2025

	(in millions)
Non-cash (loss) gain from commodity sales derivatives	$	(792)	$	22
Net settlements and premiums	(56)		(16)
Net (loss) gain from commodity sales derivatives	$	(848)	$	6

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


	Three months ended March 31,
	2026		2025

	(in millions)
Non-cash loss (gain) from natural gas purchase derivatives	$	12	$	(18)
Settlements	12		12
Net loss (gain) from natural gas purchase derivatives	$	24	$	(6)

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, 2026 and December 31, 2025.


March 31, 2026
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value

	(in millions)
Other current assets, net	$	17	$	(15)	$	2
Other noncurrent assets	41		(35)		6

Current liabilities	(436)		15		(421)
Noncurrent liabilities	(204)		35		(169)
	$	(582)	$	—	$	(582)


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

	(in millions)
Other current assets, net	$	193	$	(6)	$	187
Other noncurrent assets	106		(5)		101

Current liabilities	(48)		6		(42)
Noncurrent liabilities	(22)		5		(17)
	$	229	$	—	$	229

NOTE 7 INCOME TAXES

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


	Three months ended March 31,
	2026			2025
	(in millions)
(Loss) income before income taxes	$	(760)		$	162

Current income tax provision	1			12
Deferred income tax (benefit) provision	(50)			35
Income tax (benefit) provision	$	(49)		$	47

Annual effective tax rate	6		%	29		%

Our income tax (benefit) provision for interim periods is determined by applying an estimated annual effective tax rate to (loss) income before income taxes with the result adjusted for discrete items, if any, in the relevant period. Our annual effective tax rate for the three months ended March 31, 2026 differed from the U.S. statutory rate of 21% primarily due to nondeductible compensation and tax credits. For the three months ended March 31, 2025, the difference between the U.S. statutory rate of 21% and our effective tax rate is primarily due to state taxes.

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

NOTE 8 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 CO2 capture equipment, transportation assets and storage facilities. Our oil and natural gas segment operates assets located in California and Utah. Our carbon management segment operates exclusively in California.

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

The following tables provide segment profit or loss and reconciliations of segment profit or loss to total operating revenues and consolidated income before income taxes for the three months ended March 31, 2026 and 2025.


	Three months ended March 31, 2026
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Corporate/Eliminations/Other		Total

	(in millions)
Oil, natural gas and natural gas liquids sales	$	913	$	—	$	913	$	(8)	$	905




Other revenues and income(a)	7		—		7		$	(793)	(786)
Segment operating revenues	$	920	$	—	$	920	$	(801)







Total operating revenues									$	119

(a)Other revenues 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, 2026
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Corporate/Eliminations/Other		Total

	(in millions)
Segment operating revenues	$	920	$	—	$	920	$	(801)	$	119
Less:
Operating costs:
Energy operating costs	117		—		117		(7)		110
Gas processing costs	5		—		5		—		5
Non-energy operating costs	250		—		250		—		250
General and administrative expenses	23		3		26		80		106
Depreciation, depletion and amortization	128		—		128		5		133

Taxes other than on income	60		—		60		7		67


Interest expense	—		3		3		26		29
Loss from investment in unconsolidated subsidiaries	—		1		1		1		2
Net loss on natural gas purchase derivatives	—		—		—		24		24
Loss on early extinguishment of debt	—		—		—		21		21
Other non-operating expenses	—		—		—		(3)		(3)
Costs related to marketing of purchased commodities	—		—		—		23		23
Electricity generation expenses	—		—		—		5		5


Other segment expenses(a)	55		5		60		47		107
Segment profit or (loss)	$	282	$	(12)	$	270	$	(1,030)














Loss before income taxes									$	(760)

(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. Other segment expenses for Corporate/Eliminations/Other includes transportation costs from marketing activities, severance as well as merger and integration costs that are not allocated to a segment.


	Three months ended March 31, 2025
	Oil and Natural Gas		Carbon Management		Total Reportable Segments		Corporate/Eliminations/Other		Total

	(in millions)
Oil, natural gas and NGL sales to external customers	$	828	$	—	$	828	$	(14)	$	814



Other revenues and income(a)	2		—		2		96		98

Segment operating revenues	$	830	$	—	$	830	$	82







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		Corporate/Eliminations/Other		Total

	(in millions)
Segment operating revenues	$	830	$	—	$	830	$	82	$	912
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 subsidiary	—		1		1		—		1
Net (gain) loss on natural gas purchase derivatives	—		—		—		(6)		(6)
Loss on early extinguishment of debt	—		—		—		1		1
Other non-operating expenses	—		—		—		(5)		(5)
Costs related to marketing of purchased commodities	—		—		—		50		50
Electricity generation expenses	—		—		—		10		10


Other segment expenses(a)	43		18		61		22		83
Segment profit or (loss)	$	266	$	(25)	$	241	$	(79)














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. Other segment expenses for Corporate/Eliminations/Other includes transportation costs from marketing activities and other operating expenses, net that are not allocated to a segment.

The following table provides capital investment by segment and a reconciliation to our consolidated capital investment for the three months ended March 31, 2026 and 2025. We do not provide total assets by segment because it is not used by our Chief Operating Decision Maker. See Note 3 Investment in Unconsolidated Subsidiaries and Related Party Transactions for information on our investment in the Carbon TerraVault JV, which is part of our carbon management segment.


	Oil and Natural Gas		Carbon Management		Corporate and Other		Total

	(in millions)
Three months ended March 31, 2026	$	116	$	12	$	3	$	131
Three months ended March 31, 2025	$	50	$	2	$	3	$	55

NOTE 9 STOCKHOLDERS' EQUITY

Share Repurchase Program

Our Board of Directors authorized a Share Repurchase Program to acquire up to $1.78 billion of our common stock through December 31, 2027. The total value of shares that may yet be purchased under the Share Repurchase Program totaled $600 million as of March 31, 2026. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares, and our Board of Directors may modify, suspend or discontinue authorization of the program at any time.

The following table summarizes our share repurchases, 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, 2026	218,719	$	10	$	45.70
Three months ended March 31, 2025	2,271,919	$	101	$	44.00

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

Dividends

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


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

Three months ended March 31, 2026	$	36	$	0.4050
Three months ended March 31, 2025	$	35	$	0.3875

In addition to dividends on our common stock shown in the table above, we paid $2 million of dividend equivalents on equity-settled stock-based compensation awards in the three months ended March 31, 2026 and $1 million of dividend equivalents in the three months ended March 31, 2025. Future cash dividends, and the establishment of record and payment dates, are subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. See Note 15 Subsequent Events for information on future cash dividends.

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, 2026 and 2025. 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, 2026 and 2025:


	Three months ended March 31,
	2026		2025

	(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS
Net (loss) income	$	(711)	$	115





Denominator for Basic EPS
Weighted-average shares	88.7		90.6

Potential common shares, if dilutive:

Restricted stock units	—		0.4
Performance stock units	—		0.2

Denominator for Diluted EPS
Weighted-average shares	88.7		91.2

EPS
Basic	$	(8.02)	$	1.27
Diluted	$	(8.02)	$	1.26

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


	Three months ended March 31,
	2026	2025
	(in millions)
Shares issuable upon settlement of RSUs	1.1	—
Shares issuable upon settlement of PSUs	0.8	—
Total antidilutive shares	1.9	—

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, 2026 and 2025:



	Three months ended March 31,
	2026
	Pension Benefit		Postretirement Benefit

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



	Three months ended March 31,
	2025
	Pension Benefit		Postretirement Benefit

	(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)
Net periodic benefit costs	$	(2)	$	(1)

Contributions to our pension benefit plans were insignificant during the three months ended March 31, 2026 and the three months ended March 31, 2025. We do not expect to need to make any contributions to our qualified pension plans to satisfy minimum funding requirements during the remainder of 2026. We expect to contribute an insignificant amount to fund our non-qualified pension benefit distributions during the remainder of 2026.

NOTE 12 SUPPLEMENTAL ACCOUNT BALANCES

Restricted cash — Cash and cash equivalents includes restricted cash of $15 million at both March 31, 2026 and December 31, 2025. 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. The Aera Merger Agreement provides that 50% of the amount of released funds exceeding the cumulative abandonment and habitat restoration expenditures from January 1, 2024 onward is payable to the prior owners of Aera. We do not expect this return of excess cash to be significant.

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,
	2026		2025

	(in millions)
Oil	$	834	$	736
Natural gas	29		28
Natural gas liquids	42		50
Oil, natural gas and natural gas liquids sales	$	905	$	814

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,
	2026		2025


	(in millions)
Oil	$	20	$	22
Natural gas	16		36
Natural gas liquids	5		6
Revenue from marketing of purchased commodities	$	41	$	64

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


	March 31,		December 31,
	2026		2025

	(in millions)
Materials and supplies	$	101	$	98
Finished goods	6		8
Inventory	$	107	$	106

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


	March 31,		December 31,
	2026		2025

	(in millions)
Net amounts due from joint interest partners(a)	$	63	$	56

Fair value of commodity derivative contracts	2		187
Prepaid expenses	45		38
Greenhouse gas allowances	1		—

Income tax receivable	52		52

Other	17		20
Other current assets, net	$	180	$	353

(a)The amounts due from joint interest partners include $1 million and $2 million of allowances for credit losses for the three months ended March 31, 2026 and 2025, respectively.

Other noncurrent assets — Other noncurrent assets include the following:



	March 31,		December 31,
	2026		2025

	(in millions)
Operating lease right-of-use assets	$	77	$	83
Deferred financing costs - Revolving Credit Facility	19		20
Emission reduction credits	11		11

Fair value of commodity derivative contracts	6		101
Funded pension	100		97
Postretirement plan	19		19
Other	42		42
Other noncurrent assets	$	274	$	373

Accrued liabilities — Accrued liabilities include the following:


	March 31,		December 31,
	2026		2025

	(in millions)
Compensation-related liabilities	$	89	$	159

Taxes other than on income	104		105
Asset retirement obligations - current portion	125		120
Interest	41		12
Operating lease liability	13		15

Premiums due on commodity derivative contracts	77		22



Advanced payments	11		19



Greenhouse gas liability	—		27
Signal Hill offshore platform expense accrual	18		13
Other	70		64
Accrued liabilities	$	548	$	556

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



	March 31,		December 31,
	2026		2025

	(in millions)
Compensation-related liabilities	$	44	$	48
Postretirement and pension benefit plans	56		57
Operating lease liability	55		61


Contingent liability(a)	120		117
Other	22		29
Other long-term liabilities	$	297	$	312

(a) See Note 3 Investment in Unconsolidated Subsidiaries and Related Party Transactions for information on the contingent liability related to the Carbon TerraVault JV.

NOTE 13 SUPPLEMENTAL CASH FLOW INFORMATION

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


	Three months ended March 31,
	2026		2025

	(in millions)
Supplemental cash flow information
Interest paid, net of amounts capitalized	$	6	$	9
Income taxes paid	$	—	$	—
Interest income	$	1	$	3

Supplemental disclosure of non-cash investing and financing activities
Contributions to the Carbon TerraVault JV	$	3	$	4
Issuance of shares for stock-based compensation awards	$	21	$	21
Dividend equivalents for stock-based compensation awards	$	1	$	1
Excise tax on share repurchases	$	—	$	1

NOTE 14 CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have designated certain of our subsidiaries as Unrestricted Subsidiaries under the indenture governing our 2029 Senior Notes (2029 Senior Notes Indenture) and 2034 Senior Notes (2034 Senior Notes Indenture). Unrestricted Subsidiaries (as defined in the 2029 Senior Notes Indenture and 2034 Senior Notes Indenture) are subject to fewer restrictions under the indentures. We are required under the 2029 Senior Notes Indenture and 2034 Senior Notes Indenture to present the financial condition and results of operations of CRC and its Restricted Subsidiaries (as defined in the 2029 Senior Notes Indenture and 2034 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, 2026 and December 31, 2025 and the condensed consolidating statements of operations for the three months ended March 31, 2026 and 2025, 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. In the three months ended March 31, 2026, we adjusted the Unrestricted Subsidiaries under the 2029 Senior Notes Indenture and the 2034 Senior Notes Indenture. The Unrestricted Subsidiaries and Restricted Subsidiaries for prior periods have not been conformed to the current presentation.

Condensed Consolidating Balance Sheets

As of March 31, 2026 and December 31, 2025


	As of March 31, 2026
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total current assets	$	120	$	25	$	643	$	—	$	788
Total property, plant and equipment, net	27		408		5,469		—		5,904
Investments in consolidated subsidiaries	4,519		322		12,724		(17,565)		—
Deferred tax asset	81		—		—		—		81
Investment in unconsolidated subsidiaries	—		59		43		—		102
Other assets	22		51		201		—		274
TOTAL ASSETS	$	4,769	$	865	$	19,080	$	(17,565)	$	7,149

Total current liabilities	173		10		1,258		—		1,441
Long-term debt	1,310		—		—		—		1,310
Fair value of derivative contracts	—		—		169		—		169
Asset retirement obligations	—		—		906		—		906
Other long-term liabilities	106		129		62		—		297
Deferred tax liability	108		—		—		—		108
Amounts due to (from) affiliates	154		29		(183)		—		—
Total equity	2,918		697		16,868		(17,565)		2,918
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	4,769	$	865	$	19,080	$	(17,565)	$	7,149


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

	(in millions)
Total current assets	$	203	$	20	$	715	$	—	$	938
Total property, plant and equipment, net	27		21		5,857		—		5,905
Investments in consolidated subsidiaries	6,579		(51)		18,099		(24,627)		—
Deferred tax asset	76		—		—		—		76
Investment in unconsolidated subsidiary	—		57		54		—		111
Other assets	22		31		320		—		373
TOTAL ASSETS	$	6,907	$	78	$	25,045	$	(24,627)	$	7,403

Total current liabilities	180		6		864		—		1,050
Long-term debt	1,283		—		—		—		1,283
Fair value of derivative contracts	—		—		17		—		17
Asset retirement obligations	—		—		913		—		913
Other long-term liabilities	110		130		72		—		312
Amounts due to (from) affiliates	1,508		61		(1,569)		—		—
Deferred tax liability	154		—		—		—		154
Total equity	3,674		(120)		24,747		(24,627)		3,674
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	6,909	$	77	$	25,044	$	(24,627)	$	7,403

Condensed Consolidating Statement of Operations

For the three months ended March 31, 2026 and 2025


	Three months ended March 31, 2026
	Parent		Combined Unrestricted Subsidiaries		Combined Restricted Subsidiaries		Eliminations		Consolidated

	(in millions)
Total operating revenues	$	1	$	17	$	140	$	(39)	$	119
Total costs and other	119		37		712		(38)		830

Non-operating (loss) income	(48)		(3)		2		—		(49)
LOSS BEFORE INCOME TAXES	(166)		(23)		(570)		(1)		(760)
Income tax benefit	49		—		—		—		49
NET LOSS	$	(117)	$	(23)	$	(570)	$	(1)	$	(711)


	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

NOTE 15 SUBSEQUENT EVENTS

Ninth Amendment to the Revolving Credit Facility

On April 14, 2026, we entered into the ninth amendment to our Revolving Credit Facility to, among other things, amend the pricing grid to reduce interest margin by 0.25%, remove the 0.10% Term SOFR adjustment, and other technical amendments. Our borrowing base of $1.5 billion was reaffirmed as part of this amendment.

Dividend

On May 5, 2026, our Board of Directors declared a quarterly cash dividend of $0.4050 per share of common stock. The dividend is payable to shareholders of record at the close of business on May 29, 2026 and is expected to be paid on June 18, 2026.

Item 2Management’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, are heavily influenced by commodity prices. Oil and natural gas prices and differentials can fluctuate significantly due to various market-related factors, making it challenging to predict realized prices reliably. We may respond to changing economic conditions by adjusting the amount and allocation of our capital program or by pursuing additional cost reductions. Significant changes in oil and natural gas prices may also affect the quantities of reserves that we can economically produce over the longer term.

Global oil prices increased significantly towards the end of the three months ended March 31, 2026 and continuing to date through the second quarter due to military conflicts and geopolitical tensions. In March 2026, oil prices escalated sharply as Middle East crude and product flows from the region were interrupted due to damage to regional energy infrastructure and the effective closure of the Strait of Hormuz. Additionally, oil prices were affected to a lesser extent by Ukrainian military strikes that significantly impacted Russian export capabilities. We expect oil prices to remain volatile as these geopolitical circumstances continue to evolve. Refer to Results of Our Oil and Natural Gas Operations, Production, Prices and Realizations below for information on our realized prices.

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


	Three months ended
	March 31,		December 31,
	2026		2025
Brent oil ($/Bbl)	$	77.90	$	63.08
WTI oil ($/Bbl)	$	71.93	$	59.14
NYMEX Henry Hub ($/MMBtu)	$	5.04	$	3.55

Supply Chain and Inflation

We continued to experience relatively flat pricing from our suppliers during the first three months of 2026 compared to the prior year. U.S. tariff policy regarding both country of origin and material type remains highly uncertain and subject to future changes. During 2025, the United States significantly expanded tariff rates on imported goods, including increasing Section 232 tariffs on steel and aluminum to 50% and adding copper at the same rate. In February 2026, the Supreme Court ruled that the President's use of emergency powers under the International Emergency Economic Powers Act to impose country-specific "reciprocal" tariffs was unconstitutional; however, Section 232 metals tariffs were not affected by this ruling. In April 2026, the Federal government further restructured the Section 232 metals tariffs establishing a tiered rate structure based on metal content and applying tariffs to the full customs value of imported articles rather than only the embedded metal content.

These expanded and restructured tariff rates are expected to increase our cost of oilfield goods and extend delivery lead times over the longer term. The shift to full-value assessment for derivative articles, in particular, may increase duty burdens on certain imported components and assemblies beyond prior levels. Overall, we expect a slight impact from tariffs on our supply chain in 2026. We believe we can mitigate a portion of these cost increases through bulk purchases, domestic sourcing, and ongoing review of product classifications and supplier origin. However, the evolving nature of tariff policy — including the potential for future modifications, legal challenges, and new product inclusions — creates continued uncertainty that may limit our ability to fully offset these impacts.

High fuel costs are adversely impacting transportation and equipment prices, and high oil prices are impacting oil-based products such as chemicals and lubricants. At current oil prices, we expect these costs to increase by $6 million to $8 million for the remainder of 2026.

Marketing Arrangements

In early 2026 Valero ceased purchasing crude oil for its Benicia refinery and it is reported that the refinery ceased operations in April 2026. While we have historically sold a portion of our crude oil to this refinery, we have not experienced difficulty in selling our production to the remaining refineries in California or any negative impact on pricing or realizations as a result of this closure.

In March 2026, the United States Secretary of Energy issued an order under the authority of the Defense Production Act of 1950 directing Sable Offshore Corp. (Sable) to restart oil and gas production at the San Ynez Unit, located in Federal offshore waters, and to facilitate the movement of offshore crude oil into California via the Las Flores pipeline. The State of California and other non-governmental organizations have filed suit against the United States Secretary of Energy and Sable, the owner of the San Ynez Unit, to block transportation of this crude oil into California. However, Sable has indicated that it is currently producing crude oil and has the potential to increase production to approximately 60,000 barrels per day. We expect that this additional production could strain existing pipeline transportation capacity required to reach refiners, which could require us to find alternative routes to market that may be limited or more costly. In addition, we expect that this production will have the potential to compete with our crude oil production in the California refining market.

Regulatory Updates

Well Permitting

During the three months ended March 31, 2026, we received permits for 66 new oil and gas wells, 21 workovers and 2 sidetracks. We currently hold sufficient permits to support a seven rig program, which includes 6 rigs in California and 1 rig in Utah, in the second half of 2026.

Water Injection

Our operations in the Wilmington Oil Field use injection wells to reinject produced water under approved waterflooding plans. CalGEM has issued a directive to reduce the injection well pressure in a gradual manner in accordance with a five-year injection reduction work plan. The first phase of reduction commenced July 1, 2024, and a second reduction began in January 2025. We expect that the next phase of reduction will remain on hold until the fall of 2026 while we evaluate the impact of the previously implemented reductions together with CalGEM. We currently estimate a negligible impact on production and reserves under the existing work plan. However, material changes to the existing plan could require revisions to these estimates.

CA Cap-and-Invest (AB 1207 and SB 840)

In January 2026, the California Air Resources Board released proposed amendments to update its existing Cap-and-Invest program. The rulemaking process is ongoing, and the final terms and requirements of any proposed amendments have not yet been determined. We are actively monitoring these developments and potential impacts to our business.

Statements of Operations Analysis

Our consolidated results of operations include the results of Berry beginning on December 18, 2025, the closing date of the Berry Merger. For more information on the Berry Merger, see Part I, Item 1 – Financial Statements, Note 2 Business Combination. The Berry Merger affected the comparability of our financial results for the three months ended March 31, 2026 to the prior comparative period.

Consolidated Results of Operations

Three months ended March 31, 2026 compared to December 31, 2025

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


	Three months ended
	March 31, 2026		December 31, 2025

	(in millions)
Oil, natural gas and natural gas liquids sales	$	905	$	679
Net (loss) gain from commodity sales derivatives	(848)		126
Revenue from marketing of purchased commodities	41		60
Electricity revenue	11		52
Other revenue	10		7
Total operating revenues	$	119	$	924

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 $905 million for the three months ended March 31, 2026, which was an increase of $226 million compared to $679 million for the three months ended December 31, 2025. Oil, natural gas and natural gas liquids sales included $131 million and $18 million for the three months ended March 31, 2026 and December 31, 2025, respectively, related to sales of additional production from the Berry properties following the completion of the Berry Merger on December 18, 2025.

The following table shows changes in oil, natural gas and natural gas liquids sales for the three months ended March 31, 2026 compared to the three months ended December 31, 2025:


	Oil		NGLs		Natural Gas		Total Operations

	(in millions)
Three months ended December 31, 2025	$	614	$	39	$	26	$	679
Changes in realized prices	134		2		(4)		132
Changes in production and other	86		1		2		89
Changes in intersegment revenues	—		—		5		5

Three months ended March 31, 2026	$	834	$	42	$	29	$	905

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

Net (loss) gain from commodity sales derivatives — We report gains and losses on our derivative contracts related to sales of our oil and marketing activities in operating revenues. Net loss from commodity sales derivatives was $848 million for the three months ended March 31, 2026 compared to a net gain of $126 million for the three months ended December 31, 2025. The change primarily resulted from the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period. Oil prices significantly increased as of March 31, 2026 compared to December 31, 2025. For instance, the Brent forward curve for the twelve months following March 31, 2026 increased by approximately 40% to $83.66 compared to $60.30 at December 31, 2025. As of March 31, 2026, we have hedges on approximately 65% of our expected oil production for the remainder of 2026 at a weighted average floor price of $64.99. Gains and losses from our commodity derivative contracts are shown in the table below:


	Three months ended
	March 31, 2026		December 31, 2025
	(in millions)
Non-cash (loss) gain from commodity sales derivatives	$	(792)	$	95
Net settlements and premiums	(56)		31
Net (loss) gain from commodity sales derivatives	$	(848)	$	126

Revenue from marketing of purchased commodities — Revenue from marketing of purchased commodities was $41 million for the three months ended March 31, 2026 compared to $60 million for the three months ended December 31, 2025. The decrease was related to lower natural gas prices in California resulting from high storage levels.

Electricity revenue — Electricity revenue decreased by $41 million to $11 million for the three months ended March 31, 2026 compared to $52 million for the three months ended December 31, 2025. This decrease was primarily a result of reduced resource adequacy revenues as well as less electricity generated in response to market conditions during the three months ended March 31, 2026 compared to the three months ended December 31, 2025.

The following table presents our consolidated operating and non-operating expenses and income for the three months ended March 31, 2026 and December 31, 2025.


	Three months ended
	March 31, 2026		December 31, 2025

	(in millions)
Operating expenses
Operating costs	$	365	$	325
General and administrative expenses	106		95
Depreciation, depletion and amortization	133		129
Asset impairment	—		57
Taxes other than on income	67		55

Costs related to marketing of purchased commodities	23		47
Electricity generation expenses	5		12
Transportation costs	26		20
Accretion expense	27		29
Net loss from natural gas purchase derivatives	24		26


Other operating expenses, net	54		82
Total operating expenses	830		877

Operating (loss) income	(711)		47

Non-operating (expenses) income

Interest and debt expense, net	(29)		(29)
Loss on early extinguishment of debt	(21)		—
Equity loss from unconsolidated subsidiaries	(2)		(1)
Other non-operating income, net	3		6
(Loss) income before income taxes	(760)		23
Income tax benefit (provision)	49		(11)
Net (loss) income	$	(711)	$	12

Operating costs — The following table presents our operating costs for the three months ended March 31, 2026 and December 31, 2025:


	Three months ended
	March 31, 2026		December 31, 2025

	(in millions)

Energy operating costs	$	110	$	101
Gas processing costs	5		4
Non-energy operating costs	250		220
Operating costs	$	365	$	325

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

Energy operating costs — Energy operating costs for the three months ended March 31, 2026 were $110 million, which was an increase of $9 million from $101 million for the three months ended December 31, 2025 primarily due to the addition of the effect of the Berry properties as part of the Berry Merger. Excluding the Berry properties, energy operating costs decreased as a result of lower natural gas prices in the three months ended March 31, 2026 compared to the three months ended December 31, 2025.

Non-energy operating costs — Non-energy operating costs for the three months ended March 31, 2026 were $250 million, which was an increase of $30 million from $220 million for the three months ended December 31, 2025 primarily due to the addition of the Berry properties following the Berry Merger. Excluding the Berry properties, non-energy operating costs decreased for the three months ended March 31, 2026 compared to the three months ended December 31, 2025 primarily due to lower compensation-related costs and less workover and surface maintenance activity.

General and administrative expenses — General and administrative (G&A) expenses were $106 million for the three months ended March 31, 2026 compared to $95 million for the three months ended December 31, 2025. The increase primarily resulted from the Berry Merger including $12 million from higher compensation-related costs related to the addition of the Berry workforce and $3 million of incremental insurance cost. Additionally, cash-settled stock-based compensation expense increased by $7 million due to higher value on our incentive awards resulting from an increase in our stock price at March 31, 2026 compared to December 31, 2025. We also had higher legal costs in the three months ended March 31, 2026 compared to the three months ended December 31, 2025. Offsetting these increases, compensation-related expenses decreased $10 million in the three months ended March 31, 2026 compared to the three months ended December 31, 2025 due to the reduction of annual incentive compensation accruals.

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. Similarly, any future decrease in our stock price will result in lower compensation expense. Equity-settled stock-based compensation awards are not similarly adjusted for changes in our stock price. General and administrative expenses for equity-settled stock-based compensation, was approximately $7 million for the three months ended March 31, 2026 and $6 million for the three months ended December 31, 2025.

Asset impairment — We did not record an asset impairment in the three months ended March 31, 2026. We recognized an asset impairment during the three months ended December 31, 2025 of $57 million related to the write-down of our proved natural gas properties in the Sacramento basin. For more information, refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Property, Plant and Equipment in our 2025 Annual Report for more information.

Taxes other than on income — Taxes other than on income for the three months ended March 31, 2026 were $67 million, which was an increase of $12 million from $55 million for the three months ended December 31, 2025. The increase was primarily due to an increase in ad valorem and production taxes resulting from the Berry Merger.

Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $23 million for the three months ended March 31, 2026 compared to $47 million for the three months ended December 31, 2025. The decrease was primarily a result of lower natural gas prices and volumes purchased in the three months ended March 31, 2026.

Other operating expenses, net — Other operating expenses, net decreased $28 million to $54 million for the three months ended March 31, 2026 compared to $82 million for the three months ended December 31, 2025. For the three months ended March 31, 2026 and December 31, 2025, other operating expenses, net includes the following:


	Three months ended
	March 31, 2026		December 31, 2025
	(in millions)
Carbon management expenses	$	5	$	12
Transaction and integration costs	3		20
Severance and termination costs	23		12
Offshore platforms maintenance and abandonment costs	10		12

Information technology infrastructure	2		2
Environmental remediation	—		6
All other	11		18
Total other operating expenses, net	$	54	$	82

Income taxes – The income tax provision for the three months ended March 31, 2026 was a benefit of $49 million (representing an effective tax benefit of 6%), compared to a provision of $11 million (representing an effective tax rate of 48%) for the three months ended December 31, 2025. The effective tax rate for the three months ended March 31, 2026, reflects nondeductible compensation and tax credit. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes.

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, 2026 and December 31, 2025.


	Three months ended
	March 31,		December 31,
	2026		2025

	(in millions, except as otherwise stated)

Production and oil and gas segment financial data
Net production sold (MBoe/d)	154		137
Total operating revenues	$	920	$	695
Segment profit	$	282	$	46

Items affecting comparability:
Asset impairments(a)	$	—	$	57


Key operating expenses per Boe
Operating costs	$	26.78	$	26.33
Operating costs, after hedges on purchased natural gas	$	27.66	$	26.69
General and administrative expenses(b)	$	1.66	$	1.03
Depreciation, depletion and amortization(c)	$	9.22	$	10.04
Taxes other than on income	$	4.32	$	3.64

(a)Asset impairment for the three months ended December 31, 2025 includes the write-down of our proved properties in the Sacramento basin.

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

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

Production, Prices, and Realizations

Net Production Sold

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


	Three months ended
	March 31,	December 31,
	2026	2025
Oil (MBbl/d)
San Joaquin Basin	96	82
Los Angeles Basin	17	17
Uinta Basin	3	1
Other Basins	8	9

Total	124	109
NGLs (MBbl/d)
San Joaquin Basin	10	9



Total	10	9
Natural gas (MMcf/d)
San Joaquin Basin	95	97
Los Angeles Basin	1	1
Sacramento Basin	10	11
Uinta Basin	8	1
Other Basins	3	3
Total	117	113

Total Net Production Sold (MBoe/d)	154	137

Total average net production sold increased by 17 MBoe/d to 154 MBoe/d for the three months ended March 31, 2026 compared to 137 MBoe/d for the three months ended December 31, 2025. The increase included 19 MBoe/d related to the addition of the Berry properties. Excluding the impact of the Berry production, our net production decreased by 1 MBoe/d primarily as a result of natural decline, offset by development results. Additionally our production-sharing contracts (PSCs), which are described below, negatively impacted our net oil production by 1 MBoe/d in the three months ended March 31, 2026 compared to the three months ended December 31, 2025.

Production-Sharing Contracts

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

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 2025 Annual Report.

Prices and Realizations

The following table sets forth the average realized prices and price realizations (as a percentage of average Brent, WTI and NYMEX Henry Hub, as applicable) for the commodities we sell in the periods presented:


	Three months ended
	March 31, 2026			December 31, 2025
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	77.90		$	63.08

Realized price without derivative settlements	$	74.53	96%	$	61.14	97%
Derivative settlements	(5.16)			3.13
Realized price with derivative settlements	$	69.37	89%	$	64.27	102%

WTI	$	71.93		$	59.14

Realized price without derivative settlements	$	74.53	104%	$	61.14	103%
Realized price with derivative settlements	$	69.37	96%	$	64.27	109%

Natural Gas Liquids ($ per Bbl)
Realized price (% of Brent)	$	44.98	58%	$	42.86	68%
Realized price (% of WTI)	$	44.98	63%	$	42.86	72%

Natural gas
NYMEX Henry Hub ($/MMBtu)	$	5.04		$	3.55

Realized price ($/Mcf)	$	3.56	71%	$	3.91	110%

Oil — Brent crude oil prices for the three months ended March 31, 2026 were volatile as market focus during the period shifted from a developing oversupply situation to shortages driven by the military conflict in the Middle East and escalating crude infrastructure damage in Russia. For the three months ended March 31, 2026, Brent crude oil prices averaged $77.90 per barrel which was higher than $63.08 for the three months ended December 31, 2025.

NGLs — Realizations on natural gas liquids during the three months ended March 31, 2026 decreased compared to the three months ended December 31, 2025 as propane inventories built despite seasonal demand. California NGLs maintained a material premium to the broader North American NGL market.

Natural Gas — North American natural gas prices for the three months ended March 31, 2026 were generally higher compared to the three months ended December 31, 2025 as the Eastern part of the country experienced unseasonably cold weather. California natural gas prices for the three months ended March 31, 2026 were lower than the three months ended December 31, 2025 as warmer-than-normal temperatures and an abundance of storage impacted prices.

Results of Our Carbon Management Segment

Our carbon management segment, which we refer to as Carbon TerraVault, primarily pursues the development of CCS projects. We expect that our Carbon TerraVault CCS projects will inject CO2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO2 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 CO2 emissions. We recently completed construction of our first carbon capture project at our cryogenic gas processing facility and are preparing for first injection, subject to commissioning and final regulatory approval. We define carbon management expense to be our direct operating costs to run our carbon management segment.

The following table includes results for our carbon management segment for the three months ended March 31, 2026 and December 31, 2025.


	Three months ended
	March 31,		December 31,
	2026		2025

	(in millions)
Segment loss	$	(12)	$	(20)



Carbon management expenses	$	5	$	12
Segment general and administrative expenses	$	3	$	3
Loss from investment in the Carbon TerraVault JV	$	1	$	2

Carbon management expenses decreased for the three months ended March 31, 2026 compared to the three months ended December 31, 2025 as a result of lower easement costs.

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, 2026 were for capital investments and payment of dividends.

The following table summarizes our liquidity:



	March 31, 2026
	(in millions)
Available cash and cash equivalents(a)	$	25
Revolving Credit Facility:
Borrowing capacity	$	1,460
Revolver balance drawn	(25)
Outstanding letters of credit	(184)
Availability	$	1,251

Liquidity	$	1,276

(a)Excludes restricted cash of $15 million.

At current commodity prices and based upon our planned 2026 capital program described below, we expect to generate operating cash flow to return cash to shareholders through dividends. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or share repurchases to the extent permitted under our Revolving Credit Facility, our 8.25% senior notes due 2029 (2029 Senior Notes), and our 7.00% senior notes due 2034 (2034 Senior Notes) (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We continue to monitor the current macroeconomic environment and will adjust our planned uses of cash as necessary. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.

Revolving Credit Facility

On April 14, 2026, the borrowing base under our Revolving Credit Facility was reaffirmed at $1.5 billion and we entered into an amendment to the Revolving Credit Facility. For more information, see Part I, Item 1 – Financial Statements, Note 15 Subsequent Events for more information.

2029 Senior Notes

In March 2026, we redeemed $350 million in face value of 2029 Senior Notes from the proceeds of an offering of additional 2034 Senior Notes. See Part I, Item 1 – Financial Statements, Note 4 Debt for more information.

2034 Senior Notes

In March 2026, we completed an offering of $350 million of additional 2034 Senior Notes. See Part I, Item 1 – Financial Statements, Note 4 Debt for more information.

Share Repurchase Program

See Part I, Item 1 – Financial Statements, Note 9 Stockholders' Equity for more information on our Share Repurchase Program.

Dividends

See Part I, Item 1 – Financial Statements, Note 15 Subsequent Events for information on a dividend declared in May 2026.

Capital Program

We entered 2026 with a capital program of $430 million to $470 million and have revised our 2026 capital program to a range of $520 million to $560 million. Of this amount, $500 million to $525 million is related to our oil and natural gas segment, $12 million to $20 million is for our carbon management segment and $8 million to $15 million is for corporate and other activities. The above amounts related to carbon management projects do not include amounts funded by Brookfield through the Carbon TerraVault JV, such as drilling injection and monitoring wells at our 26R reservoir.

With respect to oil and natural gas development, we expect to increase to a seven rig program in the second half of 2026, which includes 6 rigs in California and 1 rig in Utah. We currently hold sufficient permits to support a seven rig program in the second half of 2026.

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


	2026 Full Year Estimate	Three months ended March 31, 2026
	(in millions)
Oil and natural gas segment	$500 - $525	$	116
Carbon management segment	$12 - $20	12
Corporate and other	$8 - $15	3
Total Capital	$520 - $560	$	131

Derivatives

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

Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended March 31, 2026. 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, 2026 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt in our 2025 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

Cash Flow Analysis

Cash flows from operating activities — For the three months ended March 31, 2026, our operating cash flow decreased by $87 million to $99 million from $186 million in the same period in 2025. This decrease in operating cash flow was primarily driven by changes in working capital.

Oil production during the three months ended March 31, 2026 as compared to the same period in 2025 increased 13 MBbl/d from 111 MBbl/d to 124 MBbl/d as a result of the Berry Merger. Revenue increased as a result of the increases in production from the Berry Merger offset by lower average realized prices after derivative settlements. Average realized prices after derivative settlements for oil decreased by $2.64 per barrel to $69.37 in the three months ended March 31, 2026 from $72.01 in the same prior year period. Our derivative settlements and premiums paid for the three months ended March 31, 2026 were $68 million, which was an increase of $40 million from $28 million in the same prior year period. Further, as a result of the Berry Merger, we experienced higher operating costs, employee costs, well abandonment costs, production taxes and greenhouse gas taxes during the three months ended March 31, 2026 as compared to the same prior year period.

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,
		2026		2025

		(in millions)
Capital investments		$	(131)	$	(55)
Changes in accrued capital investments		(10)		(21)


Acquisitions		(2)		—
Distribution from unconsolidated subsidiary		10		—

Other, net		(3)		(3)
Net cash used in investing activities		$	(136)	$	(79)

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,
		2026		2025

		(in millions)
Proceeds from Revolving Credit Facility		$	245	—
Repayments of Revolving Credit Facility		(220)		—
Proceeds from 2034 Senior Notes, net		347		—



Repurchases of common stock(a)		(10)		(101)
Common stock dividends		(36)		(35)
Dividend equivalents on equity-settled awards		(2)		(1)

Issuance of common stock		—		6

Debt redemption		(367)		(123)




Shares cancelled for taxes		(12)		(11)
Net cash used in financing activities		$	(55)	$	(265)

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

For the three months ended March 31, 2026, our cash flow used in financing activities was $55 million compared to $265 million in the same period in 2025. In the three months ended March 31, 2026, we completed an add-on to our 2034 Senior Notes and redeemed $350 million in face value of our 2029 Senior Notes. In the three months ended March 31, 2025, we repurchased $101 million of our common stock and redeemed $123 million of our 2026 Senior Notes.

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 2025 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 and Ukraine and geopolitical uncertainty in the Middle East, including the current conflict in Iran, and Venezuela;

•the ability to successfully execute integration efforts in connection with the Berry 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;

•refinery closures and reductions in pipeline transportation capacity;

•the expected timing and resumption of the issuance of well permits following the enactment of SB 237;

•the efforts of activists to delay or 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 the ability and financial resources to execute our capital plan in a timely manner;

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

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

•the recoverability of resources and unexpected geologic conditions;

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

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

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

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

•any failure of risk management;

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

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

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

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

•reorganization or restructuring of our operations;

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

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

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

•our ability to grow and develop our carbon management segment and achieve projected injection and storage rates;

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

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

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

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

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

•changes in interest rates;

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

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

•effects of hedging transactions;

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

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

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

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

•transaction costs;

•unknown liabilities; and

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

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 3Quantitative and Qualitative Disclosures About Market Risk

For the three months ended March 31, 2026, 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 2025 Annual Report.

Commodity Price Risk

Our financial results are sensitive to fluctuations in oil, NGL and natural gas prices. Increases in commodity prices generally result in higher revenues from commodity sales, while increases in natural gas prices also result in higher operating costs. 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, 2026, we had a net liability of $582 million for our commodity derivative positions which are carried at fair value. We estimate that a $10/bbl increase in Brent oil forward prices could increase our settlement payments by $195 million in 2026, limiting our upside. We estimate that a $10/bbl decrease in Brent oil forward prices could decrease our settlement payments by $152 million in 2026, negating the downside price movement for hedged volumes.

As of March 31, 2026, we have hedges on approximately 65% of our expected oil production for the remainder of 2026 at a weighted average floor price of $64.99. As of March 31, 2026, our hedges for purchased natural gas approximate 61% of our expected fuel use in oil and natural gas operations for the remainder of 2026 at a fixed price of $4.00.

For more information on our derivative positions as of March 31, 2026, refer to Part I, Item 1 – Financial Statements, Note 6 Derivatives.

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, 2026, 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, 2026 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 $25 million of variable-rate debt outstanding as of March 31, 2026. Our 2029 Senior Notes bear interest at a fixed rate of 8.250% per annum. Our 2034 Senior Notes bear interest at a fixed rate of 7.000% per annum.

Item 4Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer supervised and participated in management's evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2026.

There were no changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the three months ended March 31, 2026 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION

Item 1Legal 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 2025 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 2025 Annual Report. There were no material changes to those risk factors during the three months ended March 31, 2026.

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds

Share Repurchases

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.78 billion of our common stock through December 31, 2027. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend or discontinue authorization of the program at any time. Shares repurchased are either retired or held as treasury stock.

Our share repurchase activity for the three months ended March 31, 2026 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, 2026 - January 31, 2026	218,719	$	45.70	218,719	$	—
February 1, 2026 - February 28, 2026	—	$	—	—	—
March 1, 2026 - March 31, 2026	—	$	—	—	—
Total	218,719	$	45.70	218,719	$	—

(a)The total value of shares that may yet be purchased under the Share Repurchase Program totaled $600 million as of March 31, 2026.

Item 5 Other Disclosures

Rule 10b5-1 Trading Arrangements

On March 5, 2026 Jay A. Bys, our Executive Vice President and Chief Commercial Officer, entered into a Rule 10b5-1 trading arrangement intended to satisfy the affirmative defense of Rule 10b5-1(c). The trading arrangement will be in effect from June 4, 2026 and expires November 30, 2026, but may be terminated at an earlier date in accordance with the terms of the arrangement. An aggregate of up to 35,721 shares may be sold pursuant to this trading arrangement.

During the three months ended March 31, 2026, no other directors or officers adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408 of Regulation S-K.

Item 6 Exhibits


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

3.1			Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 to Registrant’s Registration Statement on Form 8-A filed October 27, 2020 and incorporated herein by reference).

3.2			Certificate of Amendment of Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 to Registrant's Current Report on Form 8-K filed on May 6, 2022 and incorporated herein by reference).

3.3			Certificate of Amendment of Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 to Registrant's Current Report on Form 8-K filed on May 1, 2023 and incorporated herein by reference).

3.4			Amended and Restated Bylaws of California Resources Corporation (filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form 8-A filed October 27, 2020 and incorporated herein by reference).

4.1*			T hird S upplemental Indenture to the 2029 Note s Indenture, date d as of January 16, 2026 , by and among the Company, the Guarantors and the Trustee.

4.2			F irst Supplemental Indenture to the 2034 Notes Indenture, date d as of Janu ary 16, 2026, by and among the Company, the Guarantors and the Trustee (filed as Exhibit 4.2 to the Registrant's Current Report on March 23, 2026 and incorporated herein by reference ).

10.1			Ninth Ame ndment to the Amended and Restated Credit Agreement, entered into effective as of April 14 , 2026 , by and amo ng California Resources Corporation , as the Borrower, the several lenders from time to time parties thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.1 to Reg istrant's Current Report on Form 8-K filed on April 17 , 2026 and incorporated herein by reference).

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

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

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

101.INS*			Inline XBRL Instance Document.

101.SCH*			Inline XBRL Taxonomy Extension Schema Document.

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

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

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

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

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

* - Filed or furnished herewith

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

SIGNATURES

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