California Resources Corporation Reports Fourth Quarter and Full-Year 2025 Financial and Operating Results; Announces 2026 Guidance

25% Year-Over-Year Production Growth and Highest Annual Free Cash Flow Since 2021

Receipt of New Drilling Permits Supports Planned 2026 Drilling Program

LONG BEACH, Calif., March 02, 2026 (GLOBE NEWSWIRE) -- California Resources Corporation (NYSE: CRC) (CRC) today reported its financial and operating results for the fourth quarter and full-year 2025. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Monday, March 2, 2026. Conference call details can be found within this release.

Fourth Quarter Highlights

• Reported net income of $12 million, adjusted net income¹ of $40 million and $251 million of adjusted EBITDAX¹
• Generated net cash provided by operating activities of $235 million and $115 million of free cash flow¹
• Delivered an average of 137 thousand barrels of oil equivalent per day⁵ (MBoe/d) (80% oil); invested total capital of $120 million including drilling, completions and workover capital¹ of $56 million
• Increased annual dividend by 5%; marking four consecutive years of dividend growth²
• Returned $59 million to shareholders including $34 million in dividends and $25 million in share repurchases²
• Closed all-stock combination with Berry Corporation on December 18, 2025
• Announced a new memorandum of understanding (MOU)⁴ with a leading California power producer to provide CO₂ transportation and storage and explore decarbonized power solutions near Silicon Valley. See California Resources Corporation and Middle River Power to Advance Decarbonized Power Solutions in California for additional information
  
  

2025 Highlights

• Increased average net production by 25% year-over-year to 138 MBoe/d⁵ (79% oil), and realized $235 million in Aera merger-related synergies
• Reported net income of $363 million, adjusted net income¹ of $359 million and highest annual adjusted EBITDAX¹ of $1,241 million since 2021
• Generated $865 million of net cash provided by operating activities and free cash flow¹ of $543 million, highest annual free cash flow since 2021
• Returned $513 million to shareholders including $377 million in share repurchases and $136 million in dividends²
• Lowered base decline to 8%–13% from 10%–15% through improved reservoir management
• Increased proved undeveloped reserves by 190% and total proved reserves by 20% through operational improvements and mergers, despite 14% year-over-year decline in SEC pricing for oil
• Exited 2025 with $117 million in available cash³, $1,284 million in available borrowing capacity and liquidity of $1,401 million
• Increased aggregate elected commitment under the Revolving Credit Facility to $1,460 million in 2025 from $1,150 million
• Received “Grade A” certifications under MiQ’s Methane Emissions Performance Standard for production assets across the Los Angeles, Ventura, and San Joaquin basins (excluding assets added in the Berry Merger)
• Substantially completed construction of CRC's first carbon capture and storage (CCS) project at the Elk Hills cryogenic gas plant
• Executed new MOUs⁴ with leading California industrial and power partners to evaluate decarbonized solutions. See Carbon TerraVault's 2025 Press Release for additional information
  
  

2026 Outlook

• CRC is receiving new drilling permits and currently holds the majority of permits necessary to undertake its 2026 capital program
• Targeting approximately 12% year-over-year production growth, averaging 152–157 MBoe/d (~81% oil), supported by four operated drilling rigs
• Capital investments expected to range between $430–$470 million, including $280–$300 million for drilling, completions, and workovers¹, and $12–$20 million for carbon management initiatives
• Expect to realize $80–$90 million of Berry merger-related synergies within 12 months of closing, including $35 to $40 million in general and administrative expenses, $25 to $30 million in operating costs and $20 million in financing costs
• Targeting first CO₂ injection at its CCS project at the Elk Hills cryogenic gas plant in spring 2026, subject to commissioning and final regulatory approval. See Carbon TerraVault's 2025 Press Release for additional information
  
  

“CRC delivered a landmark year in 2025, driven by strong financial performance, robust cash flow generation, and disciplined execution, while returning substantial cash to shareholders,” said Francisco Leon, CRC’s President and Chief Executive Officer. “Our teams made meaningful progress improving reservoir management across our high-quality, low-decline conventional asset base and advancing several strategic initiatives that strengthen the company’s long-term foundation.

"Our 2026 priorities are clear: safely and efficiently operate our core businesses, deliver on the synergies from the Berry merger, and continue to advance high-return opportunities across our portfolio while maintaining financial discipline. With a resilient asset base and a strong hedge position, CRC is well positioned to manage near-term volatility and generate strong cash flows from which to enhance shareholder returns.”

Fourth Quarter and Total Year 2025 Results

Select Production, Price and Financial Results and Non-GAAP Measures		4th Quarter				3rd Quarter				Total Year				Total Year
($ in millions except production and prices)		2025				2025				2025				2024
Net oil production per day (MBbl/d)6			109				107				109				80
Realized oil price without derivative settlements ($ per Bbl)		$	61.14			$	66.32			$	66.52			$	76.92
Realized oil price with derivative settlements1($ per Bbl)1		$	64.27			$	67.04			$	67.51			$	75.66
Net NGL production per day (MBbl/d)6			9				10				10				10
Realized NGL price ($ per Bbl)		$	42.86			$	41.04			$	45.30			$	48.93
Net natural gas production per day (Mmcf/d)6			113				118				114				117
Realized natural gas price ($ per Mcf)		$	3.91			$	3.47			$	3.57			$	2.99
Net total production per day (MBoe/d)6			137				137				138				110
Margin from purchased commodities1		$	13			$	14			$	56			$	42
Electricity margin1		$	40			$	90			$	195			$	119
Net gain (loss) from commodity derivatives		$	126			$	(23	)		$	266			$	241
Other operating expenses net of other revenue1		$	75			$	25			$	187			$	213

Select Financial Statement Data and Non-GAAP Measures:		4th Quarter				3rd Quarter			Total Year				Total Year
($ and shares in millions, except per share amounts)		2025				2025			2025				2024
Total operating revenues		$	924			$	855		$	3,669			$	3,198
Operating costs		$	325			$	316		$	1,252			$	966
General and administrative expenses		$	95			$	87		$	333			$	321
Adjusted general and administrative expenses1		$	89			$	82		$	309			$	279
Taxes other than on income		$	55			$	70		$	242			$	242
Transportation costs		$	20			$	19		$	79			$	81
Operating income		$	47			$	98		$	598			$	620
Interest and debt expense, net		$	29			$	25		$	106			$	87
Income tax provision		$	11			$	11		$	139			$	140
Deferred income tax provision		$	22			$	35		$	98			$	71
Net income		$	12			$	64		$	363			$	376
Weighted-average common shares outstanding - diluted			85.1				84.4			87.4				81.4
Net income per share - diluted		$	0.14			$	0.76		$	4.15			$	4.62
Adjusted net income1		$	40			$	123		$	359			$	317
Adjusted net income per share1- diluted		$	0.47			$	1.46		$	4.11			$	3.89
Net cash provided by operating activities		$	235			$	279		$	865			$	610
Adjusted EBITDAX1		$	251			$	338		$	1,241			$	1,006
Free cash flow1		$	115			$	188		$	543			$	355
Capital investments		$	120			$	91		$	322			$	255
Cash and cash equivalents (as of December 31, 2025 and 2024, respectively)									$	132			$	372
Available cash and cash equivalents									$	117			$	354
Restricted cash									$	15			$	18

2025 Proved Reserves

As of December 31, 2025, CRC's total proved reserves were 654 million Boe (MMBoe), of which approximately 83% was oil and 541 MMBoe was proved developed. CRC added 93 MMBoe of proved reserves related to the Berry merger in 2025. Standardized measure of discounted future net cash flows were $6,666 million with a PV-10¹ value of $8,717 million, based on SEC pricing, at December 31, 2025. In 2025, CRC's reserve replacement ratio¹ was 368%. See Attachment 3 for the non-GAAP reconciliation.

2026 Guidance

The following table provides key first quarter and full year 2026 financial and operating guidance⁶. In 2026, CRC expects to operate a four-rig program subject to commodity prices and market conditions. CRC currently holds the permits necessary to execute a majority of its planned capital program. See Attachment 2 for further information on CRC's first quarter and full year 2026 guidance.

	1Q26E	Total Year 2026E
Net Production (MBoe/d)	155 - 157	152 - 157
Percentage Oil	81%	1
Capital Investments ($ millions)	$110 - $130	$430 - $470
Adjusted EBITDAX1($ millions)	$240 - $280	$970 - $1,070

Shareholder Returns

CRC is committed to increasing shareholder returns over time. In November 2025, CRC increased its annual dividend by approximately 5% to a total annual dividend of $1.62. CRC has increased its dividend every year since 2021.

On March 1, 2026, CRC's Board of Directors declared a quarterly cash dividend of $0.405 per share of common stock, payable to shareholders of record on March 13, 2026. The dividend is expected to be paid on March 20, 2026.

In 2025, CRC repurchased 8.3 million shares of its common stock for $377 million² at an average price of $45.29 per share and returned $136 million in dividends to shareholders. Since mid-2021, the Company has returned approximately $1,573 million to shareholders², including $1,170 million in share repurchases and $403 million in dividends.

In February 2026, CRC’s Board of Directors approved an increase of the Share Repurchase Program to $1.78 billion, an increase of $430 million and extended the program through December 31, 2027. After this increase and repurchases in January 2026, CRC has $600 million of capacity remaining under the repurchase program as of February 28, 2026.

Balance Sheet and Liquidity

In October 2025, CRC's lenders reaffirmed its $1,500 million borrowing base under its Revolving Credit Facility as part of its semi-annual redetermination. In December 2025, elected commitments under the Revolving Credit Facility increased by $10 million to $1,460 million.

At year-end 2025, CRC had liquidity of $1,401 million, consisting of $117 million in available cash and cash equivalents³ and $1,284 million of available borrowing capacity under its Revolving Credit Facility (which reflects $1,460 million of borrowing capacity less $176 million of outstanding letters of credit). There were no outstanding borrowings under the Revolving Credit Facility as of December 31, 2025.

Participation in Upcoming Investor Conferences

CRC is scheduled to participate in the following events in March 2026:

• 2026 Jefferies Power, Energy, Clean Energy, and Utilities Conference, March 4, New York, NY
• 2026 NYSE Investor Access Day, March 20, Virtual
• 38th Annual ROTH Conference, March 23, Dana Point, CA
  
  

CRC’s presentation materials will be available on the day of the event on its website. See the Events and Presentations page under the Investor Relations section on www.crc.com.

Conference Call Details

A conference call and webcast is planned for 1 p.m. ET (10 a.m. PT) on Monday, March 2, 2026. To participate in the call, dial (877) 328-5505 (International calls dial +1 (412) 317-5421) or access via webcast at www.crc.com. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10204776/10070090c28. A digital replay of the conference call will be available for approximately 90 days.

_{¹ See Attachment 3 for the non-GAAP financial measures of adjusted net income (loss), adjusted net income (loss) per share - basic and diluted, net cash provided by operating activities before changes in operating assets and liabilities, net, adjusted EBITDAX, free cash flow, adjusted general and administrative expenses and PV-10 including reconciliations to the most directly comparable GAAP measure without unreasonable effort. See Attachment 2 for the 1Q26 and 2026 estimates of the non-GAAP measures of adjusted EBITDAX, oil and natural gas segment adjusted EBITDAX, carbon management segment adjusted EBITDAX and adjusted general and administrative expenses, including reconciliations to its most directly comparable GAAP measure, without unreasonable effort. See Attachment 1 for a reconciliation of drilling completion and workover capital to total capital investments reported under GAAP.
² All of CRC’s future quarterly dividends and share repurchases are subject to commodity prices, debt agreement covenants and Board of Directors' approval. The total value of shares purchased excludes commissions and excise taxes. Commissions paid on share repurchases were not significant in all periods presented. The total value of share repurchases excludes excise taxes of approximately $2 million in the year ended December 31, 2024. Excise taxes were insignificant in the year ended December 31, 2025. The total value of shares repurchased excludes approximately $3 million related to excise taxes and commissions paid on share repurchases since the inception of the Share Repurchase Program.
³ Excludes restricted cash of $15 million.
⁴ MOUs and CDMAs are non-binding agreements. The projects and transactions described in an MOU or CDMA are subject to certain conditions precedent, typically including the negotiation of definitive documents, a final investment decision by the parties and receipt of EPA Class VI permits and other regulatory approvals.
⁵ Net production per day for the periods presented reflects the impact of transaction timing. Aera Energy volumes contributed for the full year in 2025 and for approximately six months in 2024, while Berry Corporation volumes contributed for approximately 14 days in 2025 following the transaction close. Production amounts shown are reported results and are not presented on a pro forma basis.
⁶ 1Q26 guidance assumes Brent price of $66.42 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $5.22 per mcf. Total year 2026 guidance assumes Brent price of $65.57 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $4.13 per mcf.}

About California Resources Corporation

California Resources Corporation (CRC) is an independent energy and carbon management company advancing the energy transition. CRC is committed to environmental stewardship while safely providing local, responsibly sourced energy. CRC is also focused on maximizing the value of its land, mineral ownership, and energy expertise for decarbonization by developing CCS and other emissions reducing projects. For more information about CRC, please visit crc.com.

About Carbon TerraVault

Carbon TerraVault (CTV), CRC’s carbon management business, is developing services to capture, transport and permanently store CO₂ for its customers. CTV is engaged in a series of proposed CCS projects to inject CO₂ captured from industrial sources into depleted reservoirs deep underground for permanent sequestration. For more information, visit carbonterravault.com.

Forward-Looking Statements

Information set forth in this communication, including financial estimates and statements as to the effects of the Berry Merger, constitute “forward-looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 and other securities laws. All statements other than historical facts are forward-looking statements, and include statements regarding the benefits of the Berry Merger, CRC's future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives and intentions 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. These forward-looking statements are based upon the current beliefs and expectations of the management of CRC and are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, projected in, or implied by, such statements.

Although CRC believes the expectations and forecasts reflected in its 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 its 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 CRC’s actual results to be materially different than those expressed in its forward-looking statements are described in its most recent Annual Report on Form 10-K and its other periodic filings with the SEC. These factors include, but are not limited to: fluctuations in commodity prices; production levels and/or pricing by OPEC, OPEC+ or U.S. producers; government policy, war and political conditions and events; integration efforts and projected synergies and other benefits in connection with the Berry Merger and other acquisitions; divestitures and joint ventures; regulatory actions and changes that affect the oil and gas industry generally and us in particular; the efforts of activists to delay or prevent oil and gas activities or the development of CRC’s carbon management segment; changes in business strategy and the ability and financial resources to execute our capital plan in a timely manner; lower-than-expected production; changes to estimates of reserves and related future cash flows; the recoverability of resources and unexpected geologic conditions; general economic conditions and trends; results from operations and competition in the industries in which it operates; CRC’s ability to realize the anticipated benefits from prior or future efforts to reduce costs; environmental risks and liability; the benefits contemplated by its energy transition strategies and initiatives; CRC’s ability to successfully identify, develop and finance carbon capture and storage projects, power projects and other renewable energy efforts; delays from government approvals and otherwise that could affect the timing of first injection of CO₂; future dividends and share repurchases and de-leveraging efforts; and natural disasters, accidents, mechanical failures, power outages, labor difficulties, cybersecurity breaches or attacks or other catastrophic events.

CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the date hereof, and CRC is under no obligation, and expressly disclaims any obligation to update, alter or otherwise revise any forward-looking statements, whether as a result of new information, future events or otherwise. This communication may also contain information from third-party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and does not warrant the accuracy or completeness of such third-party information.

Contacts:

Daniel Juck (Investor Relations) 818-661-3700 [email protected]

Hailey Bonus (Media) 714-874-7732 [email protected]

Attachment 1
STATEMENTS OF OPERATIONS, SELECT FINANCIAL INFORMATION
($ and shares in millions, except per share amounts)		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
			2025				2025				2024				2025				2024
Statements of Operations:
Revenues
Oil, natural gas and natural gas liquids sales		$	679			$	715			$	826			$	2,910			$	2,537
Net gain (loss) from commodity derivatives			126				(23	)			(49	)			266				241
Revenue from marketing of purchased commodities			60				58				59				238				235
Electricity sales			52				101				39				233				159
Other revenue			7				4				2				22				26
Total operating revenues			924				855				877				3,669				3,198
Operating Expenses
Operating costs			325				316				323				1,252				966
General and administrative expenses			95				87				95				333				321
Depreciation, depletion and amortization			129				123				142				511				388
Asset impairment			57				2				1				59				14
Taxes other than on income			55				70				80				242				242
Costs related to marketing of purchased commodities			47				44				53				182				193
Electricity generation expenses			12				11				9				38				40
Transportation costs			20				19				21				79				81
Accretion expense			29				28				31				114				87
Net loss on natural gas purchase derivatives			26				27				19				50				30
Measurement period adjustments, net			—				—				(12	)			1				(12	)
Other operating expenses, net			82				29				51				209				239
Total operating expenses			877				756				813				3,070				2,589
(Loss) gain on asset divestitures			—				(1	)			4				(1	)			11
Operating Income			47				98				68				598				620
Non-Operating (Expenses) Income
Interest and debt expense, net			(29	)			(25	)			(28	)			(106	)			(87	)
Equity loss from unconsolidated subsidiaries			(1	)			(2	)			(1	)			(4	)			(10	)
Loss on early extinguishment of debt			—				—				—				(1	)			(5	)
Other non-operating income (expense), net			6				4				2				15				(2	)
Income Before Income Taxes			23				75				41				502				516
Income tax provision			(11	)			(11	)			(8	)			(139	)			(140	)
Net Income		$	12			$	64			$	33			$	363			$	376
Net income per share - basic		$	0.14			$	0.76			$	0.36			$	4.17			$	4.74
Net income per share - diluted		$	0.14			$	0.76			$	0.36			$	4.15			$	4.62
Adjusted net income		$	40			$	123			$	84			$	359			$	317
Adjusted net income per share - basic		$	0.47			$	1.47			$	0.93			$	4.13			$	4.00
Adjusted net income per share - diluted		$	0.47			$	1.46			$	0.91			$	4.11			$	3.89
Weighted-average common shares outstanding - basic			84.6				83.7				90.8				87.0				79.3
Weighted-average common shares outstanding - diluted			85.1				84.4				92.2				87.4				81.4
Effective tax rate			48	%			15	%			20	%			28	%			27	%

		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ in millions)			2025				2025				2024				2025				2024
Cash Flow Data:
Net cash provided by operating activities		$	235			$	279			$	206			$	865			$	610
Net cash used in investing activities		$	(508	)		$	(87	)		$	(67	)		$	(725	)		$	(1,077	)
Net cash provided by (used in) financing activities		$	209			$	(68	)		$	(8	)		$	(380	)		$	343
		December 31,				December 31,
($ in millions)			2025				2024
Select Balance Sheet Information:
Total current assets		$	938			$	1,024
Property, plant and equipment, net		$	5,905			$	5,680
Total current liabilities		$	1,050			$	980
Long-term debt, net		$	1,283			$	1,132
Noncurrent asset retirement obligations		$	913			$	995
Total stockholders' equity		$	3,674			$	3,538

GAINS AND LOSSES FROM COMMODITY DERIVATIVES
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)			2025				2025				2024				2025				2024
Non-cash commodity derivative gain (loss)		$	95			$	(32	)		$	(51	)		$	225			$	274
Net received (paid) on settled commodity derivatives			31				9				2				41				(33	)
Net gain (loss) from commodity derivatives		$	126			$	(23	)		$	(49	)		$	266			$	241
Non-cash derivative loss (gain)		$	22			$	24			$	5			$	24			$	(2	)
Net paid on settled commodity derivatives			4				3				14				26				32
Net loss on natural gas purchase derivatives		$	26			$	27			$	19			$	50			$	30

CAPITAL INVESTMENTS
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)			2025				2025				2024				2025				2024
Facilities(1)		$	46			$	28			$	44			$	99			$	111
Drilling and completions			38				26				17				98				69
Workovers			18				17				17				69				54
Other			9				1				—				10				—
Oil and natural gas segment			111				72				78				276				234
Carbon management segment			11				15				6				33				12
Corporate and other(1)			(2	)			4				4				13				9
Total capital investment		$	120			$	91			$	88			$	322			$	255
(1) Certain amounts previously reported in the Q1 2025 earnings release have been corrected. This correction relates to reporting of $8 million of capital as Corporate and other in Q1 2025 and this amount was reclassified to Facilities in Q4 2025.

LIQUIDITY
($ millions)		December 31, 2025				December 31, 2024
Available cash and cash equivalents(1)		$	117			$	354
Revolving credit facility:
Borrowing capacity			1,460				1,150
Outstanding letters of credit			(176	)			(167	)
Availability		$	1,284			$	983
Liquidity		$	1,401			$	1,337
(1) Excludes restricted cash of $15 million and $18 million at December 31, 2025 and December 31, 2024, respectively.

Attachment 2
CRC GUIDANCE		Consolidated 1Q26E		Oil and Natural Gas Segment		Carbon Management Segment
Net production (MBoe/d)		155 - 157
Net oil production (%)		81%
Operating costs ($ millions)		$355 - $375		$355 - $375
General and administrative expenses ($ millions)		$90 - $100		$12 - $16		$2 - $4
Adjusted general and administrative expenses ($ millions)		$85 - $90		$12 - $16		$2 - $4
Depreciation, depletion and amortization ($ millions)		$145 - $157		$140 - $150
Capital investments ($ millions)		$110 - $130		$95 - $110		$12 - $16
Adjusted EBITDAX ($ millions)		$240 - $280		$290 - $325		$(10) - $(5)
Margin from purchased commodities ($ millions)(1)		$15 - $20
Electricity revenue ($ millions)		$6 - $16
Electricity generation expenses ($ millions)		$2 - $6
Other operating expenses net of other revenue ($ millions)(2)		$10 - $20				$2 - $10
Transportation costs ($ millions)		$25 - $30		$15 - $20
Taxes other than on income ($ millions)		$65 - $75		$60 - $65
Interest and debt expense ($ millions)		$30 - $35
Other Assumptions:
Brent ($/Bbl)		$66.42
NYMEX ($/Mcf)		$5.22
Price realization oil - % of Brent:		94% - 98%
Price realization NGLs - % of Brent:		60% - 66%
Price realization natural gas - % of NYMEX:		58% - 64%
Deferred income taxes		62% - 74%
Effective tax rate		32%

CRC GUIDANCE		Consolidated 2026E		Oil and Natural Gas Segment		Carbon Management Segment
Net production (MBoe/d)		152 - 157
Net oil production (%)		81%
Operating costs ($ millions)		$1,400 - $1,500		$1,400 - $1,500
General and administrative expenses ($ millions)		$350 - $370		$50 - $60		$6 - $12
Adjusted general and administrative expenses ($ millions)		$315 - $330		$50 - $60		$6 - $12
Depreciation, depletion and amortization ($ millions)		$595 - $615		$575 - $590
Capital investments ($ millions)		$430 - $470		$410 - $435		$12 - $20
Adjusted EBITDAX ($ millions)		$970 - $1,070		$1,215 - $1,305		$(50) - $(10)
Margin from purchased commodities ($ millions)(1)		$60 - $75
Electricity revenue ($ millions)		$55 - $85
Electricity generation expenses ($ millions)		$15 - $25
Other operating expenses net of other revenue ($ millions)(2)		$20 - $30				$25 - $35
Transportation costs ($ millions)		$105 - $115		$65 - $70
Taxes other than on income ($ millions)		$275 - $285		$240 - $250
Interest and debt expense ($ millions)		$125 - $135
Other Assumptions:
Brent ($/Bbl)		$65.57
NYMEX ($/Mcf)		$4.13
Price realization oil - % of Brent:		94% - 98%
Price realization NGLs - % of Brent:		55% - 60%
Price realization natural gas - % of NYMEX:		65% - 70%
Deferred income taxes		62% - 74%
Effective tax rate		32%
(1) Margin from purchased commodities is calculated as the difference between revenue from marketing of purchased commodities and costs related to marketing of purchased commodities, and excludes costs of transportation.
(2) Other operating revenue and expenses, net is calculated as the difference between other revenue and other operating expenses, net and includes exploration expense and CMB expenses. CMB expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.
See Attachment 3 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition.

FORWARD LOOKING NON-GAAP RECONCILIATIONS A reconciliation of the non-GAAP measure of segment adjusted EBITDAX cannot be reconciled to the comparable measure of operating cash flow prepared in accordance with GAAP without unreasonable effort. We have included a reconciliation of the GAAP measure of segment profit to segment adjusted EBITDAX.
		1Q26E
		Consolidated								Oil and Natural Gas Segment						Carbon Management Segment
($ millions)		Low				High				Low			High			Low			High
General and administrative expenses		$	90			$	100			$	12		$	16		$	2		$	4
Equity-settled stock-based compensation			(5	)			(10	)			—			—			—			—
Estimated adjusted general and administrative expenses		$	85			$	90			$	12		$	16		$	2		$	4

		Consolidated
		1Q26E
($ millions)		Low			High
Net income		$	5		$	13
Interest and debt expense			30			35
Depreciation, depletion and amortization			145			157
Income taxes			2			6
Exploration expense			1			1
Loss from investment on unconsolidated subsidiaries			—			2
Unusual, infrequent and other items			23			28
Other non-cash items
Accretion expense			25			29
Stock-settled compensation			9			9
Estimated adjusted EBITDAX		$	240		$	280
Net cash provided by operating activities		$	98		$	110
Cash interest			—			4
Cash income taxes			3			9
Working capital changes			139			157
Estimated adjusted EBITDAX		$	240		$	280

		Oil and Natural Gas Segment
		1Q26E
($ millions)		Low			High
Segment profit		$	122		$	142
Depreciation, depletion and amortization			140			150
Unusual, infrequent and other items			3			4
Other non-cash items
Accretion expense			25			29
Estimated adjusted EBITDAX		$	290		$	325

		Carbon Management Segment
		1Q26E
($ millions)		Low				High
Segment loss		$	(7	)		$	(18	)
Interest and debt expense, net			1				5
Loss from investment on unconsolidated subsidiary			1				3
Estimated adjusted EBITDAX		$	(5	)		$	(10	)

		Consolidated
		1Q26E
($ millions)		Low				High
Revenue from marketing of purchased commodities		$	54			$	70
Costs related to marketing of purchased commodities			(39	)			(50	)
Margin from purchased commodities		$	15			$	20

		Consolidated
		1Q26E
($ millions)		Low				High
Other operating expenses, net		$	38			$	54
Other revenue			(28	)			(34	)
Operating expenses net of other revenue		$	10			$	20

		2026E
		Consolidated								Oil and Natural Gas Segment						Carbon Management Segment
($ millions)		Low				High				Low			High			Low			High
General and administrative expenses		$	350			$	370			$	50		$	60		$	6		$	12
Equity-settled stock-based compensation			(35	)			(40	)			—			—			—			—
Estimated adjusted general and administrative expenses		$	315			$	330			$	50		$	60		$	6		$	12

		Consolidated
		2026E
($ millions)		Low				High
Net income		$	50			$	80
Interest and debt expense			125				135
Interest income			(2	)			—
Depreciation, depletion and amortization			595				615
Income taxes			22				30
Exploration expense			5				5
Loss from investment on unconsolidated subsidiaries			1				3
Unusual, infrequent and other items			33				51
Other non-cash items
Accretion expense			105				115
Stock-settled compensation			36				36
Estimated adjusted EBITDAX		$	970			$	1,070
Net cash provided by operating activities		$	620			$	644
Cash interest			100				116
Cash income taxes			(34	)			(22	)
Working capital changes			284				332
Estimated adjusted EBITDAX		$	970			$	1,070

		Oil and Natural Gas Segment
		2026E
($ millions)		Low			High
Segment profit		$	528		$	588
Depreciation, depletion and amortization			575			590
Unusual, infrequent and other items			7			12
Other non-cash items
Accretion expense			105			115
Estimated adjusted EBITDAX		$	1,215		$	1,305

		Carbon Management Segment
		2026E
($ millions)		Low				High
Segment loss		$	(19	)		$	(77	)
Interest and debt expense, net			6				18
Loss from investment on unconsolidated subsidiary			3				9
Estimated adjusted EBITDAX		$	(10	)		$	(50	)

		Consolidated
		2026E
($ millions)		Low				High
Revenue from marketing of purchased commodities		$	240			$	265
Costs related to marketing of purchased commodities			(180	)			(190	)
Margin from purchased commodities		$	60			$	75

		Consolidated
		2026E
($ millions)		Low				High
Other operating expenses, net		$	166			$	184
Other revenue			(146	)			(154	)
Operating expenses net of other revenue		$	20			$	30

Attachment 3

NON-GAAP RECONCILIATIONS

To supplement the presentation of its financial results prepared in accordance with U.S. generally accepted accounting principles (GAAP), management uses certain non-GAAP measures to assess its financial condition, results of operations and cash flows. These measures are also widely used by the industry, the investment community and CRC's lenders. Although these are non-GAAP measures, the amounts included in the calculations were computed in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing CRC's financial performance, such as CRC's cost of capital and tax structure, as well as the effect of acquisition and development costs of CRC's assets. Management believes that the non-GAAP measures presented, when viewed in combination with CRC's financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the Company's performance. The non-GAAP measures presented herein may not be comparable to other similarly titled measures of other companies. Below are additional disclosures regarding each of these non-GAAP measures, including reconciliations to their most directly comparable GAAP measure where applicable.

ADJUSTED NET INCOME (LOSS)
Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. CRC defines adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing CRC's financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income and net income attributable to common stock per share to the non-GAAP financial measures of adjusted net income and adjusted net income per share.
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions, except per share amounts)			2025				2025				2024				2025				2024
Net income		$	12			$	64			$	33			$	363			$	376
Unusual, infrequent and other items:
Non-cash derivative (gain) loss on Brent based commodity contracts			(95	)			32				51				(225	)			(274	)
Non-cash derivative loss (gain) on natural gas derivative contracts			22				24				5				24				(2	)
Asset impairment			57				2				1				59				14
Severance and termination costs			12				—				2				20				30
Merger-related costs			20				6				1				30				57
Increased power and fuel costs due to power plant maintenance			—				—				6				—				50
Net loss (gain) on asset divestitures			—				1				(4	)			1				(11	)
Loss on early extinguishment of debt			—				—				—				1				5
Offshore platform expense			12				5				2				19				5
Litigation and settlements			—				1				5				26				12
Measurement period adjustments			—				—				—				1				—
Other, net			11				11				1				38				23
Total unusual, infrequent and other items			39				82				70				(6	)			(91	)
Income tax (benefit) provision of adjustments at the combined tax rate			(11	)			(23	)			(19	)			2				32
Adjusted net income		$	40			$	123			$	84			$	359			$	317
Net income (loss) per share – basic		$	0.14			$	0.76			$	0.36			$	4.17			$	4.74
Net income (loss) per share – diluted		$	0.14			$	0.76			$	0.36			$	4.15			$	4.62
Adjusted net income per share – basic		$	0.47			$	1.47			$	0.93			$	4.13			$	4.00
Adjusted net income per share – diluted		$	0.47			$	1.46			$	0.91			$	4.11			$	3.89

ADJUSTED EBITDAX
CRC defines adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. CRC believes this measure provides useful information in assessing its financial condition, results of operations and cash flows and is widely used by the industry, the investment community and its lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing CRC’s financial performance, such as its cost of capital and tax structure, as well as depreciation, depletion and amortization of CRC's assets. This measure should be read in conjunction with the information contained in CRC’s financial statements prepared in accordance with GAAP. A version of adjusted EBITDAX is a material component of certain of its financial covenants under CRC's Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. The following table represents a reconciliation of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX. CRC has included non-GAAP measures of adjusted EBITDAX for its oil and gas segment and its carbon management segment below. Management believes these segment non-GAAP measures are useful for investors to understand the results of our core businesses.
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions, except per BOE amounts)			2025				2025				2024				2025				2024
Net income		$	12			$	64			$	33			$	363			$	376
Interest and debt expense			29				25				28				106				87
Depreciation, depletion and amortization			129				123				142				511				388
Income tax provision			11				11				8				139				140
Exploration expense			1				—				—				2				2
Interest income			(5	)			(1	)			(4	)			(11	)			(19	)
Equity loss from unconsolidated subsidiaries			1				2				—				4				—
Unusual, infrequent and other items(1)			39				82				70				(6	)			(91	)
Non-cash items
Accretion expense			29				28				31				114				87
Stock-based compensation			6				5				6				24				23
Taxes related to acquisition accounting and other			—				—				2				—				12
Pension and post-retirement benefits			(1	)			(1	)			—				(5	)			1
Adjusted EBITDAX		$	251			$	338			$	316			$	1,241			$	1,006
Net cash provided by operating activities		$	235			$	279			$	206			$	865			$	610
Cash interest payments			42				6				42				98				88
Cash interest received			(5	)			(1	)			(4	)			(11	)			(19	)
Cash income taxes			—				6				50				45				105
Exploration expense			1				—				—				2				2
Working capital changes			(22	)			48				22				242				220
Adjusted EBITDAX		$	251			$	338			$	316			$	1,241			$	1,006
Net income per Boe		$	0.95			$	5.09			$	2.54			$	7.21			$	9.38
Adjusted EBITDAX per Boe		$	19.85			$	26.90			$	24.35			$	24.65			$	25.09
(1) See Adjusted Net Income (Loss) reconciliation.

SEGMENT ADJUSTED EBITDAX
This measure should be read in conjunction with Note 16Segment Informationin CRC’s 2024 Annual Report. A reconciliation of the non-GAAP measure of segment adjusted EBITDAX cannot be reconciled to the comparable measure of operating cash flow prepared in accordance with GAAP without unreasonable effort.
Oil and Natural Gas Segment		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)			2025				2025				2024				2025			2024(1)
Segment profit		$	46			$	182			$	268			$	688			$	815
Depreciation, depletion and amortization			127				118				129				492				354
Exploration expense			1				—				—				2				2
Accretion expense			29				28				31				114				87
Adjusted income items			16				4				(3	)			23				54
Adjusted EBITDAX - Oil and Natural Gas		$	219			$	332			$	425			$	1,319			$	1,312
Carbon Management Segment
Segment loss		$	(20	)		$	(21	)		$	(31	)		$	(86	)		$	(94	)
Interest on contingent liability (related to Carbon TerraVault JV)			3				3				3				11				9
Equity loss from unconsolidated subsidiary			2				2				2				6				5
Adjusted income items			57				2				1				59				2
Adjusted EBITDAX - Carbon Management		$	42			$	(14	)		$	(25	)		$	(10	)		$	(78	)
(1) Certain amounts related to the total year 2024 previously reported in the Q4 2024 earnings release have been corrected. These corrections related to classification of expenditures by segment and have no material impact on the company's overall financial position.

FREE CASH FLOW
Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow.
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)			2025				2025				2024				2025				2024
Net cash provided by operating activities		$	235			$	279			$	206			$	865			$	610
Capital investments			(120	)			(91	)			(88	)			(322	)			(255	)
Free cash flow		$	115			$	188			$	118			$	543			$	355

ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES
Management uses a measure called adjusted general and administrative (G&A) expenses and adjusted G&A per BOE to provide useful information to investors interested in comparing CRC's costs between periods and performance to its peers.
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)			2025				2025				2024				2025				2024
General and administrative expenses		$	95			$	87			$	95			$	333			$	321
Stock-based compensation			(6	)			(5	)			(6	)			(24	)			(23	)
Information technology infrastructure			—				—				—				—				(3	)
Accelerated vesting			—				—				(3	)			—				(12	)
Retention awards			—				—				—				—				(2	)
Other			—				—				(1	)			—				(2	)
Adjusted G&A expenses		$	89			$	82			$	85			$	309			$	279
G&A per BOE		$	7.51			$	6.92			$	7.32			$	6.61			$	8.01
Adjusted G&A per BOE		$	7.04			$	6.52			$	6.55			$	6.14			$	6.96

MARGIN FROM PURCHASED COMMODITIES
Management uses a measure called margin from purchased commodities, which is calculated as the difference between revenue from purchased commodities and costs related to purchased commodities. This non-GAAP measure excludes transportation costs.
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)			2025				2025				2024				2025				2024
Revenue from purchased commodities		$	60			$	58			$	59			$	238			$	235
Costs related to purchased commodities			(47	)			(44	)			(53	)			(182	)			(193	)
Margin from purchased commodities		$	13			$	14			$	6			$	56			$	42

ELECTRICITY MARGIN
Management uses a measure called electricity margin, which is calculated as the difference between electricity sales and electricity generation expenses.
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)			2025				2025				2024				2025				2024
Electricity sales		$	52			$	101			$	39			$	233			$	159
Electricity generation expenses			(12	)			(11	)			(9	)			(38	)			(40	)
Electricity margin		$	40			$	90			$	30			$	195			$	119

OTHER OPERATING EXPENSES NET OF OTHER REVENUE
Management uses a measure called other operating expenses net of other revenue, which is calculated as the difference between other operating expenses, net and other revenue.
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)			2025				2025				2024				2025				2024
Other operating expenses, net(1)		$	82			$	29			$	51			$	209			$	239
Other revenue			(7	)			(4	)			(2	)			(22	)			(26	)
Other operating expenses net of other revenue		$	75			$	25			$	49			$	187			$	213
(1) Other operating expenses, net includes carbon management expenses beginning in 2025. Amounts from 2024 have been represented to conform to the 2025 presentation.

PV-10 AND STANDARDIZED MEASURE
The following table presents a reconciliation of the standardized measure of discounted future net cash flows (Standardized Measure) to the non-GAAP financial measure of PV-10 of cash flows:
($ millions)			As of December 31, 2025
Standardized Measure			$	6,666
Present value of future income taxes discounted at 10%				2,051
PV-10 of cash flows(*)			$	8,717
(*) PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of oil and natural gas reserves. Standardized Measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing costs and discount assumptions. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.

RESERVE REPLACEMENT RATIO
The reserve replacement ratio is a measure that management uses to gauge the growth of its reserves relative to production over the same period. There is no guarantee that historical sources of reserve additions will continue as many factors fully or partially outside management's control, including commodity prices, availability of capital and the underlying geology, affect reserves additions. We calculate the reserve replacement ratio considering reserve additions resulting from extensions and discoveries, improved recovery, revisions in previous estimates related to performance and acquisitions and divestitures. Other oil and gas producers may use different methods to calculate the replacement ratio, which may affect comparability.
		2025
		(MMBoe)
Net performance-related revisions		61
Extensions and discoveries		3
Improved recovery		27
Acquisitions		93
Reserve additions		184
Production (MMboe)		50
Reserve Replacement Ratio		368		%

Attachment 4
PRODUCTION STATISTICS
		4th Quarter		3rd Quarter		4th Quarter		Total Year		Total Year
Net Production Per Day		2025		2025		2024		2025		2024
Oil (MBbl/d)
San Joaquin Basin		82		81		86		83		58
Los Angeles Basin		17		17		17		17		17
Uinta Basin		1		—		—		—		—
Other Basins		9		9		9		9		5
Total		109		107		112		109		80
NGLs (MBbl/d)
San Joaquin Basin		9		10		10		10		10
Total		9		10		10		10		10
Natural Gas (MMcf/d)
San Joaquin Basin		97		103		98		99		99
Los Angeles Basin		1		1		1		1		1
Sacramento Basin		11		11		13		12		13
Uinta Basin		1		—		—		—		—
Other Basins		3		3		3		2		4
Total		113		118		115		114		117
Total Net Production (MBoe/d)		137		137		141		138		110

Gross Operated and Net Non-Operated		4th Quarter		3rd Quarter		4th Quarter		Total Year		Total Year
Production Per Day		2025		2025		2024		2025		2024
Oil (MBbl/d)
San Joaquin Basin		88		86		93		89		63
Los Angeles Basin		21		21		23		21		23
Uinta Basin		1		—		—		—		—
Other Basins		10		11		11		11		6
Total		120		118		127		121		92
NGLs (MBbl/d)
San Joaquin Basin		11		11		10		11		11
Other Basins		—		—		1		—		—
Total		11		11		11		11		11
Natural Gas (MMcf/d)
San Joaquin Basin		130		133		135		133		131
Los Angeles Basin		6		6		6		6		7
Sacramento Basin		14		14		17		14		17
Uinta Basin		1		—		—		—		—
Other Basins		4		4		3		3		2
Total		155		157		161		156		157
Total Gross Production (MBoe/d)		157		155		165		158		129

Attachment 5
PRICE STATISTICS
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
			2025				2025				2024				2025				2024
Oil ($ per Bbl)
Realized price with derivative settlements		$	64.27			$	67.04			$	73.00			$	67.51			$	75.66
Realized price without derivative settlements		$	61.14			$	66.32			$	72.82			$	66.52			$	76.92
NGLs ($/Bbl)		$	42.86			$	41.04			$	52.62			$	45.30			$	48.93
Natural gas ($/Mcf)
Realized price with derivative settlements		$	3.91			$	3.47			$	3.65			$	3.57			$	2.99
Realized price without derivative settlements		$	3.91			$	3.47			$	3.65			$	3.57			$	2.99
Index Prices
Brent oil ($/Bbl)		$	63.08			$	68.13			$	73.97			$	68.22			$	79.84
WTI oil ($/Bbl)		$	59.14			$	64.93			$	70.27			$	64.81			$	75.72
NYMEX average monthly settled price ($/MMBtu)		$	3.55			$	3.07			$	2.79			$	3.43			$	2.27
Realized Prices as Percentage of Index Prices
Oil with derivative settlements as a percentage of Brent			102	%			98	%			99	%			99	%			95	%
Oil without derivative settlements as a percentage of Brent			97	%			97	%			98	%			98	%			96	%
Oil with derivative settlements as a percentage of WTI			109	%			103	%			104	%			104	%			100	%
Oil without derivative settlements as a percentage of WTI			103	%			102	%			104	%			103	%			102	%
NGLs as a percentage of Brent			68	%			60	%			71	%			66	%			61	%
NGLs as a percentage of WTI			72	%			63	%			75	%			70	%			65	%
Natural gas with derivative settlements as a percentage of NYMEX contract month average			110	%			113	%			131	%			104	%			132	%
Natural gas without derivative settlements as a percentage of NYMEX contract month average			110	%			113	%			131	%			104	%			132	%

Attachment 6
FOURTH QUARTER 2025 DRILLING ACTIVITY
		San Joaquin		Los Angeles		Ventura		Sacramento
Wells Drilled		Basin		Basin		Basin		Basin		Total
Development Wells
Primary		3		—		—		—		3
Waterflood		10		—		—		—		10
Steamflood		18		—		—		—		18
Total(1)		31		—		—		—		31
TOTAL YEAR 2025 DRILLING ACTIVITY
		San Joaquin		Los Angeles		Ventura		Sacramento
Wells Drilled		Basin		Basin		Basin		Basin		Total
Development Wells
Primary		9		—		—		—		9
Waterflood		37		—		—		—		37
Steamflood		30		—		—		—		30
Total(1)		76		—		—		—		76
(1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled.