California Resources Corporation Reports Third Quarter 2026 Financial and Operating Results

Raised Quarterly Dividend by 4% and Delivered 2% Quarter-over-Quarter Net Production Growth 

Sharpened Focus on California through Uinta Basin Sale and Closing of Crimson Midstream Acquisition

LONG BEACH, Calif., Nov. 02, 2026 (GLOBE NEWSWIRE) -- California Resources Corporation (NYSE: CRC) today reported its financial and operating results for the third quarter of 2026. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Tuesday, November 3, 2026. Conference call details can be found within this release.

Third Quarter Highlights

• Delivered average net production of 152 thousand barrels of oil equivalent per day (MBoe/d) (80% oil)
• Reported a net loss of $315 million which includes the non-cash loss of $540 million from changes in the fair value of outstanding commodity derivatives, adjusted net income¹ of $104 million and $341 million of adjusted EBITDAX¹ which exceeded quarterly guidance
• Generated net cash provided by operating activities of $305 million, deployed $158 million of total capital and delivered $147 million of free cash flow¹
• Returned $66 million to shareholders, including $36 million in dividends and $30 million in share repurchases²
• Increased quarterly dividend by 4%, reinforcing commitment to sustainable shareholder returns; declared quarterly dividend of $0.42/share to be paid in the fourth quarter of 2026²
• Ended the quarter with $1,280 million in borrowing capacity and $35 million in available cash and cash equivalents³, representing $1,315 million of liquidity^{1, 3}

Other Highlights

• Announced a memorandum of understanding⁴ (MOU) with Bloom Energy to jointly evaluate and target the potential development of 1 gigawatt (GW) or more of solid-oxide fuel cell power generation paired with carbon capture and storage. See California Resources Corporation Announces Strategic Collaboration with Bloom Energy to Advance Decarbonized Power Across California for additional information
• Signed agreement to divest its Uinta Basin (Utah) assets for total cash consideration of approximately $90 million, subject to customary purchase price adjustments. The transaction is expected to close by year-end, subject to certain third-party consents and other customary closing conditions. See California Resources Corporation Announces Divestiture of Uinta Basin Assets for additional information
• Closed its all-cash acquisition of Crimson Midstream Holdings, LLC (“Crimson”), strengthening CRC’s Leading Energy Infrastructure Platform and expanding options for potential longer-term development of CO₂ transportation across California. See California Resources Corporation Completes Acquisition of Crimson for additional information
• Published the 2025 Sustainability Update providing an overview of CRC's sustainability efforts and performance

"Our team continues to execute exceptionally well through strong operational performance, synergy realization from our strategic initiatives and impressive free cash flow,” said Francisco Leon, CRC’s President and Chief Executive Officer. “Through continued capital discipline and the ongoing focus on sustainable efficiency gains, we are improving free cash flow and our liquidity profile. In addition, we remain committed to our shareholder capital return program with share repurchases and dividends, the latter demonstrated by the 4% dividend per share increase we announced today. We have also made significant progress on strategic priorities, including the Crimson pipeline acquisition, along with the Uinta Basin asset sale and Bloom Energy partnership. These initiatives broaden and strengthen our commitment to the Golden State while continuing to deliver value to all CRC constituents including our shareholders and California communities.”

Third Quarter 2026 Results

• Net NGL and natural gas production exceeded guidance by approximately 1 MBoe/d, supported by the new Belridge-Elk Hills connection and California’s first carbon capture and storage (CCS) project at CRC’s Elk Hills Cryogenic Gas Plant, which led to increased gas processing and NGL recovery
• Electricity revenue net of electricity generation expenses exceeded guidance primarily due to higher prices for resource adequacy revenue and sales from electricity delivered to the wholesale market as Elk Hills power plant ran at a higher operational capacity
• Operating expenses were higher than anticipated and increased over the prior period, primarily due to higher prices for natural gas purchased and used in steamflood operations, and higher workover activity

Select Production, Price and Financial Results and Non-GAAP Measures		3rd Quarter					2nd Quarter
($ in millions except production and prices)		2026					2026
Net oil production per day (MBbl/d)			121					120
Realized oil price without derivative settlements ($ per Bbl)		$	83.42				$	91.55
Realized oil price with derivative settlements ($ per Bbl)1		$	72.46				$	76.43
Net NGL production per day (MBbl/d)			11					10
Realized NGL price ($ per Bbl)		$	48.57				$	49.62
Net natural gas production per day (Mmcf/d)			123					115
Realized natural gas price ($ per Mcf)		$	3.52				$	1.84
Net total production per day (MBoe/d)			152					149
Margin from purchased commodities1		$	15				$	11
Electricity revenue net of electricity generation expenses1		$	35				$	(4	)
Net (loss) gain from commodity sales derivatives1		$	(675	)			$	205
Other operating expenses net of other revenue1		$	35				$	56

Select Financial Statement Data and Non-GAAP Measures:		3rd Quarter					2nd Quarter
($ and shares in millions, except per share amounts)		2026					2026
Total operating revenues before net (loss) gain from commodity derivatives1		$	1,096				$	1,092
Operating costs		$	386				$	347
General and administrative expenses		$	89				$	97
Adjusted general and administrative expenses1		$	79				$	89
Taxes other than on income		$	81				$	66
Transportation costs		$	31				$	30
Operating (loss) income		$	(407	)			$	511
Interest and debt expense, net		$	26				$	28
Income tax benefit		$	(113	)			$	(56	)
Deferred income tax benefit		$	(113	)			$	(55	)
Net (loss) income		$	(315	)			$	514
Weighted-average common shares outstanding - diluted			88.7					89.3
Net (loss) income per share - diluted		$	(3.55	)			$	5.76
Adjusted net income1		$	104				$	88
Adjusted net income per share1 - diluted		$	1.17				$	0.99
Net cash provided by operating activities		$	305				$	263
Net cash provided by operating activities before net changes in operating assets and liabilities1		$	300				$	300
Capital investments		$	158				$	149
Adjusted EBITDAX1		$	341				$	338
Free cash flow1		$	147				$	114

Fourth Quarter 2026 Guidance and Preliminary 2027 Outlook

The following table provides select fourth quarter 2026E guidance⁵. Guidance includes the financial results of the Uinta Basin through year-end 2026, while the preliminary 2027 outlook excludes the Uinta. CRC ran an average of five rigs during the third quarter of 2026 and similarly, expects to run an average of five rigs during the fourth quarter of 2026. CRC plans to enter 2027 with six rigs in California. See Attachment 2 for CRC's fourth quarter 2026E guidance.

CRC Guidance	4Q26E
Net Production (MBoe/d)	150 - 152
Percentage Oil	79	%
Capital Investments ($ millions)	$110 - $130
Adjusted EBITDAX1 ($ millions)	$340 - $380

Leon added, "As we look to 2027, CRC is moving from acquisition to optimization. Having built, in our view, California’s leading energy infrastructure platform, our focus now turns to running it better by lowering costs, improving capital efficiency and putting our midstream, power and carbon opportunities to work. That strategy positions us to strengthen free cash flow and continue delivering meaningful returns to our shareholders."

2027 drilling, completions and workover capital is expected to be $450 - $475 million. Planned activity levels will be supported by the Company's growing permit inventory and ongoing operational efficiencies. CRC remains focused on disciplined capital allocation, maintaining a strong balance sheet and delivering sustainable shareholder returns. CRC intends to provide full-year 2027 guidance with its fourth quarter and year-end 2026 earnings release. The Company has flexibility to adjust its 2027 capital program to reflect changes in commodity prices and other market factors.

Shareholder Returns

CRC is committed to sustainably returning cash to shareholders through dividends and repurchases of its common stock. In the third quarter of 2026, CRC repurchased 0.6 million shares of its common stock for $30 million at an average price of $53.48 per share and returned $36 million in dividends to shareholders. Since 2021, the Company has returned approximately $1,721 million to shareholders, including $1,210 million in share repurchases and $511 million in dividends. As of September 30, 2026, CRC had $570 million remaining for share repurchases under its authorized Share Repurchase Program through December 31, 2027².

On November 2, 2026, CRC's Board of Directors amended its cash dividend policy to increase the anticipated total annual dividend by approximately 4% to $1.68, payable to shareholders in quarterly increments of $0.42 per share of common stock. The Board of Directors also declared a quarterly cash dividend of $0.42 per share of common stock, payable to shareholders of record on December 4, 2026. The dividend is expected to be paid on December 18, 2026².

Balance Sheet and Liquidity

As of September 30, 2026, CRC had $35 million in available cash and cash equivalents³, $1,280 million in available borrowing capacity under its Revolving Credit Facility (which reflects $1,460 million of borrowing capacity less $180 million of outstanding letters of credit) and liquidity of $1,315 million.

In October 2026, CRC entered into a new amendment to its Revolving Credit Facility to, among other things, extend the maturity date to March 2030, increase the elected commitments of its lenders to $1,470 million, re-affirm its borrowing base at $1,500 million, and implement certain other technical amendments.

Upcoming Investor Conferences

CRC is scheduled to participate in the following events through year-end 2026:

• Goldman Sachs 7th Annual Carbonomics Conference, November 10, London, UK
• Wolfe Global Oil & Gas Conference 2026, November 18, Virtual
• 2026 Stephens Annual Investment Conference, November 19, Nashville, TN
• Capital One Securities 21st Annual Energy Conference, December 1, New Orleans, LA
• UBS 30th Annual Global Technology and AI Conference 2026, December 2, Scottsdale, AZ
• Mizuho Power, Energy & Infrastructure Conference 2026, December 8, New York City, NY
• Bernstein 5th Annual Industrials & Energy Forum, December 9, New York City, NY
• 25th Annual Wells Fargo Energy and Power Symposium, December 9, New York City, NY
• Stifel 2026 Frontier Tech 2.0 Energy Summit, December 10, New York City, NY

CRC plans to post its presentation materials to its website on the day of the event. See the Events and Presentations page under the Investor Relations section at www.crc.com.

Conference Call Details

A conference call and webcast is planned for 1 p.m. ET (10 a.m. PT) on Tuesday, November 3, 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/10211602/104c2aa7a86. 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 net changes in operating assets and liabilities, adjusted EBITDAX, free cash flow, free cash flow before net changes in operating assets and liabilities, adjusted general and administrative expenses, total operating revenues before net (loss) gain from commodity derivatives, margin from purchased commodities, electricity revenue net of electricity generation expenses, other operating expenses net of other revenue and liquidity, including reconciliations to the most directly comparable GAAP measure without unreasonable effort. See Attachment 2 for the 4Q26 estimates of the non-GAAP measures of adjusted general and administrative expenses, margin from purchased commodities, electricity revenue net of electricity generation expenses and other operating expenses net of other revenue and reconciliations to its most directly comparable GAAP measure. The 4Q26 estimates of some non-GAAP measures cannot be reconciled 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, and non-cash commodity derivative (loss) gain from combined derivatives to net (loss) gain from combined derivatives, 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.
³ Excludes restricted cash of $13 million.
⁴ MOUs are non-binding agreements. The projects and transactions described in an MOU 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 4Q26 guidance assumes Brent price of $102.90 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.25 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 www.crc.com.

About Carbon TerraVault

Carbon TerraVault (CTV), CRC’s carbon management business, develops services to capture, transport and permanently store carbon dioxide (CO₂) for its customers. CTV is advancing a portfolio of carbon capture and storage (CCS) projects, including CTV I, which is now operational and injecting CO₂ for permanent sequestration in a depleted reservoir deep underground. For more information, visit www.carbonterravault.com.

Forward-Looking Statements

Information set forth in this communication, including financial estimates and statements as to the effects of the Berry Merger and the Crimson acquisition, 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 and the Crimson acquisition, 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; changes in price realizations; integration efforts and projected synergies and other benefits in connection with the Berry Merger, Crimson acquisition and other acquisitions; divestitures and joint ventures, including the Uinta divestiture; regulatory actions and changes that affect the oil and gas industry generally and CRC 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 its 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 and improve capital efficiencies; 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, transportation and storage projects, power projects and other renewable energy efforts, including those contemplated by the Bloom MOU; changes in transportation costs and CRC's ability to develop midstream opportunities; delays from government approvals and otherwise that could affect the timing of projects; 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 CRC_IR@crc.com

Hailey Bonus (Media) 714-874-7732 CRC.Communications@crc.com

Attachment 1
STATEMENTS OF OPERATIONS, SELECT FINANCIAL INFORMATION
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ and shares in millions, except per share amounts)		2026				2026				2025				2026				2025
Statements of Operations:
Revenues
Oil, natural gas and natural gas liquids sales		$	1,002			$	1,056			$	715			$	2,963			$	2,231
Net (loss) gain from commodity derivatives			(675	)			205				(23	)			(1,318	)			140
Revenue from marketing of purchased commodities			40				26				58				107				178
Electricity revenue			46				6				101				63				181
Other revenue			8				4				4				22				15
Total operating revenues			421				1,297				855				1,837				2,745
Operating Expenses
Operating costs			386				347				316				1,098				927
General and administrative expenses			89				97				87				292				238
Depreciation, depletion and amortization			137				131				123				401				382
Asset impairment			—				—				2				—				2
Taxes other than on income			81				66				70				214				187
Costs related to marketing of purchased commodities			25				15				44				63				135
Electricity generation expenses			11				10				11				26				26
Transportation costs			31				30				19				87				59
Accretion expense			26				27				28				80				85
Net (gain) loss on natural gas purchase derivatives			(1	)			5				27				28				24
Measurement period adjustments, net			—				(2	)			—				(2	)			1
Other operating expenses, net			43				60				29				157				127
Total operating expenses			828				786				756				2,444				2,193
Loss on asset divestitures			—				—				(1	)			—				(1	)
Operating (Loss) Income			(407	)			511				98				(607	)			551
Non-Operating (Expenses) Income
Interest and debt expense, net			(26	)			(28	)			(25	)			(83	)			(77	)
Equity loss from unconsolidated subsidiaries			(1	)			(2	)			(2	)			(5	)			(3	)
Loss on early extinguishment of debt			—				(28	)			—				(49	)			(1	)
Other non-operating income, net			6				5				4				14				9
(Loss) Income Before Income Taxes			(428	)			458				75				(730	)			479
Income tax benefit (provision)			113				56				(11	)			218				(128	)
Net (Loss) Income		$	(315	)		$	514			$	64			$	(512	)		$	351
Net (loss) income per share - basic		$	(3.55	)		$	5.79			$	0.76			$	(5.77	)		$	4.00
Net (loss) income per share - diluted		$	(3.55	)		$	5.76			$	0.76			$	(5.77	)		$	3.97
Adjusted net income		$	104			$	88			$	123			$	271			$	319
Adjusted net income per share - basic		$	1.17			$	0.99			$	1.47			$	3.06			$	3.63
Adjusted net income per share - diluted(1)		$	1.17			$	0.99			$	1.46			$	3.03			$	3.61
Weighted-average common shares outstanding - basic			88.7				88.8				83.7				88.7				87.8
Weighted-average common shares outstanding - diluted(1)			88.7				89.3				84.4				88.7				88.4
Effective tax rate			26	%		(12) %					15	%			30	%			27	%
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ in millions)		2026				2026				2025				2026				2025
Cash Flow Data:
Net cash provided by operating activities		$	305			$	263			$	279			$	667			$	630
Net cash used in investing activities		$	(245	)		$	(153	)		$	(87	)		$	(534	)		$	(217	)
Net cash used in financing activities		$	(68	)		$	(94	)		$	(68	)		$	(217	)		$	(589	)
		September 30				December 31,
($ in millions)		2026				2025
Select Balance Sheet Information:
Total current assets		$	820			$	938
Property, plant and equipment, net		$	5,975			$	5,905
Total current liabilities		$	1,622			$	1,050
Long-term debt, net		$	1,281			$	1,283
Noncurrent asset retirement obligations		$	888			$	913
Total stockholders' equity		$	3,025			$	3,674
(1) Adjusted net income per share - diluted for the three months ended September 30, 2026 is calculated using weighted average shares outstanding of 89.2 million shares. Adjusted net income per share - diluted for the nine months ended September 30, 2026 is calculated using weighted average shares outstanding of 89.3 million shares.

GAINS AND LOSSES FROM COMMODITY DERIVATIVES
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions)		2026				2026				2025				2026				2025
Non-cash (loss) gain from commodity sales derivatives		$	(554	)		$	370			$	(32	)		$	(976	)		$	130
Net settlements and premiums			(121	)			(165	)			9				(342	)			10
Net (loss) gain from commodity sales derivatives		$	(675	)		$	205			$	(23	)		$	(1,318	)		$	140
Non-cash (gain) loss from natural gas purchase derivatives		$	(14	)		$	(20	)		$	24			$	(22	)		$	2
Settlements			13				25				3				50				22
Net (gain) loss from natural gas purchase derivatives		$	(1	)		$	5			$	27			$	28			$	24
Non-cash (loss) gain from combined commodity derivatives		$	(540	)		$	390			$	(56	)		$	(954	)		$	128
Net settlements and premiums from combined derivatives			(134	)			(190	)			6				(392	)			(12	)
Net (loss) gain from combined commodity derivatives		$	(674	)		$	200			$	(50	)		$	(1,346	)		$	116

CAPITAL INVESTMENTS
		3rd Quarter			2nd Quarter			3rd Quarter			Nine Months			Nine Months
($ millions)		2026			2026			2025			2026			2025
Facilities		$	22		$	38		$	28		$	97		$	53
Drilling and completions			115			77			26			245			60
Workovers			18			24			17			59			51
Other			—			6			1			15			1
Oil and natural gas segment			155			145			72			416			165
Carbon management segment			1			3			15			16			22
Corporate and other			2			1			4			6			15
Total capital investment		$	158		$	149		$	91		$	438		$	202

LIQUIDITY
($ millions)		September 30, 2026				December 31, 2025
Available cash and cash equivalents(1)		$	35			$	117
Revolving credit facility:
Borrowing capacity			1,460				1,460
Outstanding letters of credit			(180	)			(176	)
Availability		$	1,280			$	1,284
Liquidity		$	1,315			$	1,401
(1) Excludes restricted cash of $13 million and $15 million at September 30, 2026 and December 31, 2025, respectively.

								Attachment 2
CRC GUIDANCE		Consolidated 4Q26E				Oil and Natural Gas Segment		Carbon Management Segment
Net production (MBoe/d)		150 - 152
Net oil production (%)		79%
Operating costs ($ millions)		$370 - $390				$370 - $390
General and administrative expenses ($ millions)		$95 - $99				$12 - $16		$0 - $2
Adjusted general and administrative expenses ($ millions)		$83 - $93				$12 - $16		$0 - $2
Depreciation, depletion and amortization ($ millions)		$128 - $140				$120 - $130
Capital investments ($ millions)		$110 - $130				$110 - $125		$0 - $2
Adjusted EBITDAX ($ millions)		$340 - $380
Margin from purchased commodities ($ millions) (1)		$11 - $15
Electricity revenue net of electricity generation expenses ($ millions)		$5 - $11
Other operating expenses net of other revenue ($ millions) (2)		$20 - $30						$4 - $12
Transportation costs ($ millions)		$30 - $35				$20 - $24
Taxes other than on income  ($ millions)		$68 - $78				$60 - $66
Interest and debt expense ($ millions)		$28 - $32
Other Assumptions:
Brent ($/Bbl)		$102.90
NYMEX ($/Mcf)		$3.25
Price realization oil - % of Brent:		91% - 93%
Price realization NGLs - % of Brent:		55% - 62%
Price realization natural gas - % of NYMEX:		110% - 116%
Current income tax provision ($ millions) (3)		$(2) - $2
Effective tax rate		27% - 31%

_{⁽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 expenses net of other revenue 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.
⁽³⁾ Current income tax composition is subject to variability and depends on a number of factors, including but not limited to, final taxable income determinations, the availability and utilization of net operating loss carryforwards (NOLs), applicable tax credits, and other differences between book and taxable income. Accordingly, the current provision may vary from period to period and should not be viewed as indicative of future tax obligations.}

FORWARD LOOKING NON-GAAP RECONCILIATIONS
		4Q26E
		Consolidated								Oil and Natural Gas Segment						Carbon Management Segment
($ millions)		Low				High				Low			High			Low			High
General and administrative expenses		$	95			$	99			$	12		$	16		$	—		$	2
Equity-settled stock-based compensation			(12	)			(6	)			—			—			—			—
Estimated adjusted general and administrative expenses		$	83			$	93			$	12		$	16		$	—		$	2

		Consolidated
		4Q26E
($ millions)		Low				High
Revenue from marketing of purchased commodities		$	30			$	46
Costs related to marketing of purchased commodities			(19	)			(31	)
Margin from purchased commodities		$	11			$	15

		Consolidated
		4Q26E
($ millions)		Low				High
Electricity revenues		$	11			$	21
Electricity generation expenses			(6	)			(10	)
Electricity revenue net of electricity generation expenses		$	5			$	11

		Consolidated
		4Q26E
($ millions)		Low				High
Other operating expenses, net		$	39			$	53
Other revenue			(19	)			(23	)
Other 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.
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions, except per share amounts)			2026				2026				2025				2026				2025
Net (loss) income		$	(315	)		$	514			$	64			$	(512	)		$	351
Unusual, infrequent and other items:
Non-cash derivative loss (gain) on Brent based commodity contracts			554				(370	)			32				976				(130	)
Non-cash derivative (gain) loss on natural gas derivative contracts			(14	)			(20	)			24				(22	)			2
Asset impairment			—				—				2				—				2
Severance and termination costs			—				—				—				25				8
Merger-related costs			3				1				6				5				10
Net loss on asset divestitures			—				—				1				—				1
Loss on early extinguishment of debt			—				28				—				49				1
Offshore platform expense			6				10				5				26				7
Litigation and settlements			—				—				1				—				26
Measurement period adjustments, net			—				(2	)			—				(2	)			1
Other, net			23				12				11				43				27
Total unusual, infrequent and other items			572				(341	)			82				1,100				(45	)
Income tax (benefit) provision of adjustments at the combined tax rate			(153	)			(85	)			(23	)			(317	)			13
Adjusted net income		$	104			$	88			$	123			$	271			$	319
Net income (loss) per share – basic		$	(3.55	)		$	5.79			$	0.76			$	(5.77	)		$	4.00
Net income (loss) per share – diluted		$	(3.55	)		$	5.76			$	0.76			$	(5.77	)		$	3.97
Adjusted net income per share – basic		$	1.17			$	0.99			$	1.47			$	3.06			$	3.63
Adjusted net income per share – diluted		$	1.17			$	0.99			$	1.46			$	3.03			$	3.61

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.   These materials include forward-looking non-GAAP financial measures, including adjusted EBITDAX. CRC is unable to provide a reconciliation of such forward-looking non-GAAP measures to the most directly comparable forward-looking GAAP financial measures because certain information needed to reconcile these measures is dependent on future events, many of which are outside of CRC’s control and cannot be reasonably predicted at this time. These items include, but are not limited to, changes in working capital, the timing and amount of capital accruals, and other non-cash or unusual items. Accordingly, a quantitative reconciliation is not available without unreasonable efforts.   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.
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions, except per BOE amounts)			2026				2026				2025				2026				2025
Net (loss) income		$	(315	)		$	514			$	64			$	(512	)		$	351
Interest and debt expense			26				28				25				83				77
Depreciation, depletion and amortization			137				131				123				401				382
Income tax (benefit) provision			(113	)			(56	)			11				(218	)			128
Interest income			—				—				(1	)			(1	)			(6	)
Equity loss from unconsolidated subsidiaries			1				2				2				5				3
Exploration expense			—				27				—				27				1
Unusual, infrequent and other items (1)			572				(341	)			82				1,100				(45	)
Non-cash items			—												—
Accretion expense			26				27				28				80				85
Stock-based compensation			9				8				5				24				18
Pension and post-retirement benefits			(2	)			(2	)			(1	)			(6	)			(4	)
Adjusted EBITDAX		$	341			$	338			$	338			$	983			$	990
Net cash provided by operating activities		$	305			$	263			$	279			$	667			$	630
Cash interest payments			44				26				6				71				56
Cash interest received			—				—				(1	)			(1	)			(6	)
Cash income taxes			—				16				6				16				45
Exploration expense			—				27				—				27				1
Working capital changes			(8	)			6				48				203				264
Adjusted EBITDAX		$	341			$	338			$	338			$	983			$	990
Net (loss) income per Boe		$	(22.51	)		$	37.93			$	5.09			$	(12.36	)		$	9.31
Adjusted EBITDAX per Boe		$	24.37			$	24.94			$	26.90			$	23.73			$	26.25
(1) See Adjusted Net Income (Loss) reconciliation.

SEGMENT ADJUSTED EBITDAX
This measure should be read in conjunction with Note 16 Segment Information in CRC’s 2025 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		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions)			2026				2026				2025				2026				2025
Segment profit		$	360			$	427			$	182			$	1,071			$	642
Depreciation, depletion and amortization			128				124				118				379				365
Exploration expense			—				27				—				27				1
Accretion expense			26				27				28				80				85
Adjusted income items			11				3				4				18				7
Adjusted EBITDAX - Oil and Natural Gas		$	525			$	608			$	332			$	1,575			$	1,100
Carbon Management Segment
Segment loss		$	(14	)		$	(13	)		$	(21	)		$	(39	)		$	(66	)
Interest on contingent liability (related to Carbon TerraVault JV)			3				3				3				9				8
Equity loss from unconsolidated subsidiary			1				2				2				4				4
Depreciation, depletion and amortization			2				—				—				2				—
Adjusted income items			—				—				2				—				2
Adjusted EBITDAX - Carbon Management		$	(8	)		$	(8	)		$	(14	)		$	(24	)		$	(52	)

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.
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions)			2026				2026				2025				2026				2025
Net cash provided by operating activities		$	305			$	263			$	279			$	667			$	630
Capital investments			(158	)			(149	)			(91	)			(438	)			(202	)
Free cash flow		$	147			$	114			$	188			$	229			$	428

FREE CASH FLOW BEFORE NET CHANGES IN OPERATING ASSETS AND LIABILITIES
Management uses free cash flow before changes in operating assets and liabilities, which is defined by CRC as net cash provided by operating activities less net changes in operating assets and liabilities and 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 before net changes in operating assets and liabilities.
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions)			2026				2026				2025				2026				2025
Net cash provided by operating activities		$	305			$	263			$	279			$	667			$	630
Net changes in operating assets and liabilities			(5	)			37				43				180				165
Net cash provided by operating activities before net changes in operating assets and liabilities			300				300				322			$	847			$	795
Capital investments			(158	)			(149	)			(91	)			(438	)			(202	)
Free cash flow before net changes in operating assets and liabilities		$	142			$	151			$	231			$	409			$	593

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.
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions)			2026				2026				2025				2026				2025
General and administrative expenses		$	89			$	97			$	87			$	292			$	238
Stock-based compensation and other			(10	)			(8	)			(5	)			(25	)			(18	)
Adjusted G&A expenses		$	79			$	89			$	82			$	267			$	220
G&A per BOE		$	6.36			$	7.16			$	6.92			$	7.05			$	6.31
Adjusted G&A per BOE		$	5.65			$	6.57			$	6.52			$	6.44			$	5.83

TOTAL OPERATING REVENUES BEFORE NET (LOSS) GAIN FROM COMMODITY DERIVATIVES
Management uses a measure called total operating revenues before net (loss) gain from commodity derivatives, which is calculated as the difference between total operating revenues less net (loss) gain from commodity derivatives.
		3rd Quarter				2nd Quarter			3rd Quarter				Nine Months				Nine Months
($ millions)			2026				2026			2025				2026			2025
Total operating revenues		$	421			$	1,297		$	855			$	1,837			$	2,745
Less: Net gain (loss) from commodity derivatives			(675	)			205			(23	)			(1,318	)			140
Total operating revenues before net gain (loss) from commodity derivatives		$	1,096			$	1,092		$	878			$	3,155			$	2,605

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.
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions)			2026				2026				2025				2026				2025
Revenue from purchased commodities		$	40			$	26			$	58			$	107			$	178
Costs related to purchased commodities			(25	)			(15	)			(44	)			(63	)			(135	)
Margin from purchased commodities		$	15			$	11			$	14			$	44			$	43

ELECTRICITY REVENUE NET OF ELECTRICITY GENERATION EXPENSES
Management uses a measure called electricity revenue net of electricity generation expenses, which is calculated as the difference between electricity revenue and electricity generation expenses.
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions)			2026				2026				2025				2026				2025
Electricity revenue		$	46			$	6			$	101			$	63			$	181
Electricity generation expenses			(11	)			(10	)			(11	)			(26	)			(26	)
Electricity revenue net of electricity generation expenses		$	35			$	(4	)		$	90			$	37			$	155

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.
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions)			2026				2026				2025				2026				2025
Other operating expenses, net		$	43			$	60			$	29			$	157			$	127
Other revenue			(8	)			(4	)			(4	)			(22	)			(15	)
Other operating expenses net of other revenue		$	35			$	56			$	25			$	135			$	112

Attachment 4
PRODUCTION STATISTICS
		3rd Quarter		2nd Quarter		3rd Quarter		Nine Months		Nine Months
Net Production Per Day		2026		2026		2025		2026		2025
Oil (MBbl/d)
San Joaquin Basin		93		93		81		94		83
Los Angeles Basin		16		15		17		16		17
Uinta Basin		2		3		—		3		—
Other Basins		10		9		9		9		9
Total		121		120		107		122		109
NGLs (MBbl/d)
San Joaquin Basin		10		10		10		10		10
Other Basins		1		—		—		—		—
Total		11		10		10		10		10
Natural Gas (MMcf/d)
San Joaquin Basin		101		93		103		96		100
Los Angeles Basin		1		1		1		1		1
Sacramento Basin		10		10		11		10		12
Uinta Basin		9		9		—		9		—
Other Basins		2		2		3		2		2
Total		123		115		118		118		115
Total Net Production (MBoe/d)		152		149		137		152		138

Gross Operated and Net Non-Operated		3rd Quarter		2nd Quarter		3rd Quarter		Nine Months		Nine Months
Production Per Day		2026		2026		2025		2026		2025
Oil (MBbl/d)
San Joaquin Basin		99		102		86		101		88
Los Angeles Basin		20		21		21		21		22
Uinta Basin		3		4		—		4		—
Other Basins		11		9		11		10		11
Total		133		136		118		136		121
NGLs (MBbl/d)
San Joaquin Basin		11		10		11		10		11
Uinta Basin		1		1		—		1		—
Total		12		11		11		11		11
Natural Gas (MMcf/d)
San Joaquin Basin		129		128		133		128		134
Los Angeles Basin		6		6		6		6		6
Sacramento Basin		13		13		14		13		14
Uinta Basin		12		12		—		12		—
Other Basins		3		3		4		3		4
Total		163		162		157		162		158
Total Gross Production (MBoe/d)		172		174		155		174		158

Attachment 5
PRICE STATISTICS
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
			2026				2026				2025				2026				2025
Oil ($ per Bbl)
Realized price with derivative settlements		$	72.46			$	76.43			$	67.04			$	72.76			$	68.61
Realized price without derivative settlements		$	83.42			$	91.55			$	66.32			$	83.08			$	68.34
NGLs ($/Bbl)		$	48.57			$	49.62			$	41.04			$	47.70			$	46.10
Natural gas ($/Mcf)
Realized price without derivative settlements		$	3.52			$	1.84			$	3.47			$	2.99			$	3.46
Index Prices
Brent oil ($/Bbl)		$	91.36			$	96.87			$	68.13			$	88.71			$	69.94
WTI oil ($/Bbl)		$	85.79			$	92.79			$	64.93			$	83.50			$	66.70
NYMEX average monthly settled price ($/MMBtu)		$	2.96			$	2.90			$	3.07			$	3.63			$	3.39
Realized Prices as Percentage of Index Prices
Oil with derivative settlements as a percentage of Brent			79	%			79	%			98	%			82	%			98	%
Oil without derivative settlements as a percentage of Brent			91	%			95	%			97	%			94	%			98	%
Oil with derivative settlements as a percentage of WTI			84	%			82	%			103	%			87	%			103	%
Oil without derivative settlements as a percentage of WTI			97	%			99	%			102	%			99	%			102	%
NGLs as a percentage of Brent			53	%			51	%			60	%			54	%			66	%
NGLs as a percentage of WTI			57	%			53	%			63	%			57	%			69	%
Natural gas without derivative settlements as a percentage of NYMEX contract month average			119	%			63	%			113	%			82	%			102	%

Attachment 6
THIRD QUARTER 2026 DRILLING ACTIVITY
		San Joaquin		Los Angeles		Sacramento		Uinta		Other
Wells Drilled		Basin		Basin		Basin		Basin		Basins		Total
Development Wells
Primary		17		—		—		3		—		20
Waterflood		2		6		—		—		—		8
Steamflood		89		—		—		—		—		89
Total (1)		108		6		—		3		—		117
NINE MONTHS 2026 DRILLING ACTIVITY
		San Joaquin		Los Angeles		Sacramento		Uinta		Other
Wells Drilled		Basin		Basin		Basin		Basin		Basins		Total
Development Wells
Primary		40		—		—		4		—		44
Waterflood		52		7		—		—		—		59
Steamflood		172		—		—		—		—		172
Total (1)		264		7		—		4				275
(1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled.