カリフォルニアリソーシズの適時開示・決算・その他

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________

FORM 8-K

_____________________

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported): August 10, 2026

_____________________

California Resources Corporation

(Exact Name of Registrant as Specified in its Charter)


Delaware	001-36478		46-5670947
(State or Other Jurisdiction of Incorporation)	(Commission File Number)		(IRS Employer Identification No.)

1 World Trade Center
Suite 1500
Long Beach
California		90831
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s Telephone Number, Including Area Code: (888) 848-4754

_____________________

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock	CRC	New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR §230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (17 CFR §240.12b-2).

Emerging growth company ☐

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

Item 2.02 Results of Operations and Financial Condition.

On August 10, 2026, California Resources Corporation (the “Company”) issued a press release announcing its financial condition and results of operations for the three and six months ended June 30, 2026. A copy of the press release is furnished as Exhibit 99.1 to this report on Form 8-K, and is incorporated herein by reference.

The information contained in this Item 2.02 and the exhibit hereto shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and shall not be incorporated by reference into any filings made by the Company under the Securities Act of 1933, as amended, or the Exchange Act, except as may be expressly set forth by specific reference in such filing.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits


Exhibit No.						Description
99.1						Press release dated August 10, 2026.
104						Cover Page Interactive Data File (embedded within the Inline XBRL document).

SIGNATURE

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


			California Resources Corporation



			/s/ Michael L. Preston
			Name:			Michael L. Preston
			Title:			Executive Vice President, Chief Strategy Officer and General Counsel

DATED: August 10, 2026

EX-99.1 2 a2026q2erex991.htm EX-99.1 Document

California Resources Corporation Reports Second Quarter 2026 Financial and Operating Results

Strengthens California's Leading Energy Platform Through Strategic Acquisition

Sustainable Operational Efficiency Gains Enhance 2026 Outlook and Further Reduces Estimated Long-Term Maintenance Capital

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

Highlights

•Delivered average net production of 149 thousand barrels of oil equivalent per day (MBoe/d) (81% oil)

•Reported net income of $514 million which includes the non-cash gain from changes in the fair value of outstanding commodity derivatives, adjusted net income1 of $88 million and $338 million of adjusted EBITDAX1

•Generated net cash provided by operating activities of $263 million or $300 million of net cash provided by operating activities before net changes in operating assets and liabilities1

•Delivered $114 million of free cash flow1 or $151 million of free cash flow before net changes in operating assets and liabilities1

•Returned $36 million to shareholders through dividends2

•Ended the quarter with $1,279 million in borrowing capacity and $43 million in available cash and cash equivalents3, representing $1,322 million of liquidity1, 3

Other Highlights

•Announced the signing of a definitive purchase agreement to acquire Crimson Midstream Holdings, LLC (“Crimson”) from CorEnergy Infrastructure Trust, Inc. for total cash consideration of $63 million, subject to customary adjustments. See California Resources Corporation Expands Integrated California Energy Infrastructure Platform Through Strategic Midstream Acquisition for additional information

•Lowered California long-term maintenance capital outlook by reducing drilling, completions and workover capital expectations by approximately 5% to a $450 million to $475 million range with six drilling rigs, compared to seven previously

•Optimized capital structure, reduced annual interest payments and extended maturities through recent $550 million offering of 7.250% senior notes due 2035 (2035 Senior Notes) and subsequent redemption of all remaining 8.250% senior notes due 2029 (2029 Senior Notes)

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•Announced the Golden Valley Technology Hub project, a proposed data center development in partnership with Beacon Data Centers (Beacon), at CRC's Elk Hills field. See www.goldenvalleytechhub.com for additional information

•Implemented more than 100% of the annual Berry merger synergy target, representing $103 million of annualized savings six months ahead of schedule

•Achieved first carbon dioxide (CO2) injection and revenue at Carbon TerraVault I (CTV I), California's inaugural carbon capture and storage (CCS) project. See Carbon TerraVault Provides Second Quarter 2026 Update for additional information

"Our teams are executing exceptionally well, delivering durable operational improvements across our asset base,” said Francisco Leon, CRC’s President and Chief Executive Officer. “Recent efficiency gains and continued Berry synergy capture are strengthening our long-term outlook. Specifically, we are now able to maintain flat California production with fewer rigs and less maintenance capital, creating operational and financial momentum into 2027 and beyond.

"Today, we also announced the planned acquisition of Crimson’s California pipeline systems and storage assets, a strategic infrastructure investment that strengthens our California platform. In parallel, our team continued to advance the Golden Valley Technology Hub with Beacon, leveraging CRC’s assets to meet California’s growing AI demand for reliable power. These developments strengthen CRC’s integrated energy platform, reinforce our commitment to California and create long-term value for our shareholders, Californians and the communities we serve.”

Second Quarter 2026 Results

•Operating expenses and general and administrative expenses were in line with expectations reflecting solid execution and the ongoing capture of Berry merger-related synergies

•Invested total capital of $149 million including drilling, completions and workover capital1 of $101 million; total capital was higher than initial expectations driven by a 25% increase in drilling activity across the California portfolio

•Built approximately 137 thousand barrels of oil (MBo) of inventory due to temporary takeaway constraints, equivalent to approximately 1.5 MBo/d, which, together with weaker differentials and higher operating and transportation costs, reduced second quarter adjusted EBITDAX1 and net cash provided by operating activities before net changes in operating assets and liabilities1 by approximately $25 million. The substantial majority of this inventory was sold in July 2026

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Select Production, Price and Financial Results and Non-GAAP Measures	2nd Quarter		1st Quarter
($ in millions except production and prices)	2026		2026
Net oil production per day (MBbl/d)	120		124
Realized oil price without derivative settlements ($ per Bbl)	$	91.55	$	74.53
Realized oil price with derivative settlements ($ per Bbl)1	$	76.43	$	69.37
Net NGL production per day (MBbl/d)	10		10
Realized NGL price ($ per Bbl)	$	49.62	$	44.98
Net natural gas production per day (Mmcf/d)	115		117
Realized natural gas price ($ per Mcf)	$	1.84	$	3.56
Net total production per day (MBoe/d)	149		154

Margin from purchased commodities1	$	11	$	18
Electricity revenue net of electricity generation expenses1	$	(4)	$	6



Net gain (loss) from commodity sales derivatives1	$	205	$	(848)
Other operating expenses net of other revenue1	$	56	$	44


Select Financial Statement Data and Non-GAAP Measures:	2nd Quarter		1st Quarter
($ and shares in millions, except per share amounts)	2026		2026


Total operating revenues before net (loss) gain from commodity derivatives1	$	1,092	$	967



Operating costs	$	347	$	365
General and administrative expenses	$	97	$	106
Adjusted general and administrative expenses1	$	89	$	99
Taxes other than on income	$	66	$	67
Transportation costs	$	30	$	26
Operating income (loss)	$	511	$	(711)
Interest and debt expense, net	$	28	$	29
Income tax benefit	$	(56)	$	(49)
Deferred income tax benefit	$	(55)	$	(50)
Net income (loss)	$	514	$	(711)
Weighted-average common shares outstanding - diluted	89.3		88.7
Net income (loss) per share - diluted	$	5.76	$	(8.02)


Adjusted net income1	$	88	$	79
Adjusted net income per share1 - diluted	$	0.99	$	0.88
Net cash provided by operating activities	$	263	$	99
Net cash provided by operating activities before net changes in operating assets and liabilities1	$	300	$	247
Capital investments	$	149	$	131
Adjusted EBITDAX1	$	338	$	304
Free cash flow1	$	114	$	(32)

2026 Guidance Highlights

CRC reaffirmed its full-year 2026 total capital outlook and reduced expected full-year 2026 drilling, completions and workover capital by $10 million to $370 million to $390 million while targeting approximately 1% entry-to-exit gross production growth. Stronger operating efficiencies across the portfolio, together with the impact of lower estimated oil prices on production-sharing contracts, provide increased confidence in achieving these targets and strengthen the Company’s long-term outlook.

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CRC expects to operate an average of five rigs in California and one rig in Utah during the second half of 2026 and currently holds sufficient permits to support its 2026 capital program. The Company also continues to build its permit inventory in support of anticipated 2027 operations. Following the closing of the pending transaction, CRC expects to provide additional financial and operating guidance. The following table provides key current third-quarter and full-year 2026 financial and operating guidance4. See Attachment 2 for additional information.


CRC Guidance	3Q26E	Total Year 2026E
Net Production (MBoe/d)	151 - 154	150 - 155
Percentage Oil	80%	80%
Capital Investments ($ millions)	$150 - $170	$520 - $560
Adjusted EBITDAX1 ($ millions)	$285 - $325	$1,200 - $1,300

Shareholder Returns

On August 10, 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 September 4, 2026. The dividend is expected to be paid on September 18, 2026.

In the second quarter 2026, CRC returned $36 million in dividends to shareholders. Since 2021, the Company has returned approximately $1,655 million to shareholders, including $1,180 million in share repurchases and $475 million in dividends2.

Balance Sheet and Liquidity

In June 2026, CRC completed an offering of $550 million of 2035 Senior Notes. The proceeds, together with cash on hand, were used to redeem all $550 million of the Company’s outstanding 2029 Senior Notes for total consideration of $573 million. The redemption resulted in a $28 million loss on extinguishment of debt, including a $23 million premium paid and $5 million write-off of unamortized debt issuance costs, net of unamortized premium. Following this redemption, CRC had outstanding $750 million of 2034 Senior Notes and $550 million of 2035 Senior Notes.

As of June 30, 2026, CRC had liquidity of $1,322 million1,3, consisting of $43 million in available cash and cash equivalents3 and $1,279 million of available borrowing capacity under its Revolving Credit Facility (which reflects $1,460 million of borrowing capacity less $181 million of outstanding letters of credit and no balance outstanding on the Revolving Credit Facility).

Participation in Upcoming Investor Conferences

CRC is scheduled to participate in the following events in August and September 2026:

•Citi 2026 Natural Resources Conference, August 12 and 13, Las Vegas, NV

•Seaport 15th Annual Summer Investor Conference, August 18, Virtual

•Daniel Energy Partners, Executive Series, September 1 to 3, Pebble Beach, CA

•Barclays 40th Annual Energy-Power Conference, September 9 and 10, New York, NY

•NYSE Energy & Utilities Investor Access Day, September 24, Virtual

•PEP Energy Conference 2026, September 29, Austin, TX

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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 at www.crc.com.

Conference Call Details

A conference call and webcast is planned for 1 p.m. ET (10 a.m. PT) on Monday, August 10, 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/10209577/1041fba52bd. 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 and other operating expenses net of other revenue, including reconciliations to the most directly comparable GAAP measure without unreasonable effort. See Attachment 2 for the 3Q26 and 2026 estimates of the non-GAAP measures of adjusted EBITDAX, adjusted general and administrative expenses, margin from purchased commodities, other operating expenses net of other revenue and electricity revenue net of electricity generation 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, 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 3Q26 guidance assumes Brent price of $83.14 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.95 per mcf. Total year 2026 guidance assumes Brent price of $84.51 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.55 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.

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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; integration efforts and projected synergies and other benefits in connection with the Berry Merger, Crimson acquisition 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.

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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

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Attachment 1
STATEMENTS OF OPERATIONS, SELECT FINANCIAL INFORMATION

	2nd Quarter			1st Quarter			2nd Quarter			Six Months			Six 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	$	1,056		$	905		$	702		$	1,961		$	1,516
Net gain (loss) from commodity derivatives	205			(848)			157			(643)			163
Revenue from marketing of purchased commodities	26			41			56			67			120
Electricity revenue	6			11			58			17			80
Other revenue	4			10			5			14			11
Total operating revenues	1,297			119			978			1,416			1,890

Operating Expenses
Operating costs	347			365			295			712			611
General and administrative expenses	97			106			79			203			151
Depreciation, depletion and amortization	131			133			128			264			259

Taxes other than on income	66			67			47			133			117

Costs related to marketing of purchased commodities	15			23			41			38			91
Electricity generation expenses	10			5			5			15			15
Transportation costs	30			26			20			56			40
Accretion expense	27			27			28			54			57
Net loss on natural gas purchase derivatives	5			24			3			29			(3)

Measurement period adjustments, net	(2)			—			—			(2)			1
Other operating expenses, net	60			54			65			114			98
Total operating expenses	786			830			711			1,616			1,437

Operating Income (Loss)	511			(711)			267			(200)			453

Non-Operating (Expenses) Income
Interest and debt expense, net	(28)			(29)			(25)			(57)			(52)
Equity loss from unconsolidated subsidiaries	(2)			(2)			—			(4)			(1)
Loss on early extinguishment of debt	(28)			(21)			—			(49)			(1)
Other non-operating income, net	5			3			—			8			5

Income (Loss) Before Income Taxes	458			(760)			242			(302)			404
Income tax benefit (provision)	56			49			(70)			105			(117)
Net Income (Loss)	$	514		$	(711)		$	172		$	(197)		$	287



Net income per share - basic	$	5.79		$	(8.02)		$	1.93		$	(2.22)		$	3.20
Net income per share - diluted	$	5.76		$	(8.02)		$	1.92		$	(2.22)		$	3.18

Adjusted net income	$	88		$	79		$	98		$	167		$	196
Adjusted net income per share - basic	$	0.99		$	0.89		$	1.10		$	1.88		$	2.18
Adjusted net income per share - diluted(1)	$	0.99		$	0.88		$	1.10		$	1.87		$	2.17

Weighted-average common shares outstanding - basic	88.8			88.7			89.0			88.7			89.8
Weighted-average common shares outstanding - diluted(1)	89.3			88.7			89.4			88.7			90.3


Effective tax rate	(12)		%	6		%	29		%	35		%	29		%

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	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ in millions)	2026		2026		2025		2026		2025
Cash Flow Data:
Net cash provided by operating activities	$	263	$	99	$	165	$	362	$	351
Net cash used in investing activities	$	(153)	$	(136)	$	(51)	$	(289)	$	(130)
Net cash used in financing activities	$	(94)	$	(55)	$	(256)	$	(149)	$	(521)

	June 30,		December 31,
($ in millions)	2026		2025
Select Balance Sheet Information:
Total current assets	$	697	$	938
Property, plant and equipment, net	$	5,923	$	5,905

Total current liabilities	$	1,055	$	1,050
Long-term debt, net	$	1,281	$	1,283
Noncurrent asset retirement obligations	$	923	$	913

Total stockholders' equity	$	3,402	$	3,674


(1) Adjusted net income per share - diluted for the three months ended March 31, 2026 is calculated using weighted average shares outstanding of 89.5 million shares. Adjusted net income per share - diluted for the six months ended June 30, 2026 is calculated using weighted average shares outstanding of 89.3 million shares.


GAINS AND LOSSES FROM COMMODITY DERIVATIVES

	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions)	2026		2026		2025		2026		2025

Non-cash gain (loss) from commodity sales derivatives	$	370	$	(792)	$	140	$	(422)	$	162
Net settlements and premiums	(165)		(56)		17		(221)		1
Net gain (loss) from commodity sales derivatives	$	205	$	(848)	$	157	$	(643)	$	163


Non-cash (gain) loss from natural gas purchase derivatives	$	(20)	$	12	$	(4)	$	(8)	$	(22)
Settlements	25		12		7		37		19
Net loss (gain) from natural gas purchase derivatives	$	5	$	24	$	3	$	29	$	(3)


Non-cash gain (loss) from combined commodity derivatives	$	390	$	(804)	$	144	$	(414)	$	184
Net settlements and premiums from combined derivatives	(190)		(68)		10		(258)		(18)
Net gain (loss) from combined commodity derivatives	$	200	$	(872)	$	154	$	(672)	$	166

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CAPITAL INVESTMENTS


	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions)	2026		2026		2025		2026		2025

Facilities(1)	$	38	$	37	$	17	$	75	$	25
Drilling and completions	77		53		19		130		34
Workovers	24		17		15		41		34
Other	6		9		—		15		—
Oil and natural gas segment	145		116		51		261		93
Carbon management segment	3		12		5		15		7
Corporate and other	1		3		—		4		11
Total capital investment	$	149	$	131	$	56	$	280	$	111


LIQUIDITY



($ millions)	June 30, 2026		December 31, 2025
Available cash and cash equivalents(1)	$	43	$	117

Revolving credit facility:
Borrowing capacity	1,460		1,460

Outstanding letters of credit	(181)		(176)
Availability	$	1,279	$	1,284

Liquidity	$	1,322	$	1,401

(1) Excludes restricted cash of $13 million and $15 million at June 30, 2026 and December 31, 2025, respectively.

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			Attachment 2
CRC GUIDANCE	Consolidated 3Q26E	Oil and Natural Gas Segment	Carbon Management Segment
Net production (MBoe/d)	151 - 154
Net oil production (%)	80%

Operating costs ($ millions)	$360 - $380	$360 - $380
General and administrative expenses ($ millions)	$82 - $92	$12 - $16	$0 - $2
Adjusted general and administrative expenses ($ millions)	$75 - $85	$12 - $16	$0 - $2
Depreciation, depletion and amortization ($ millions)	$126 - $138	$120 - $130
Capital investments ($ millions)	$150 - $170	$150 - $165	$0 - $2





Adjusted EBITDAX ($ millions)	$285 - $325

Margin from purchased commodities ($ millions) (1)	$11 - $15
Electricity revenue net of electricity generation expenses ($ millions)	$18 - $24


Other operating expenses net of other revenue ($ millions) (2)	$20 - $32		$4 - $12
Transportation costs ($ millions)	$30 - $35	$20 - $24
Taxes other than on income ($ millions)	$70 - $80	$62 - $68
Interest and debt expense ($ millions)	$27 - $31

Other Assumptions:
Brent ($/Bbl)	$83.14
NYMEX ($/Mcf)	$2.95
Price realization oil - % of Brent:	91% - 94%
Price realization NGLs - % of Brent:	48% - 54%
Price realization natural gas - % of NYMEX:	97% - 103%

Current income tax provision ($ millions) (3)	$(2) - $2
Effective tax rate	33% - 37%

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CRC GUIDANCE	Consolidated 2026E	Oil and Natural Gas Segment	Carbon Management Segment
Net production (MBoe/d)	150 - 155
Net oil production (%)	80%

Operating costs ($ millions)	$1,425 - $1,475	$1,425 - $1,475
General and administrative expenses ($ millions)	$365 - $385	$51 - $63	$4 - 10
Adjusted general and administrative expenses ($ millions)	$335 - $350	$51 - $63	$4 - 10
Depreciation, depletion and amortization ($ millions)	$520 - $540	$500 - $510
Capital investments ($ millions)	$520 - $560	$505 - $530	$10 - $18





Adjusted EBITDAX ($ millions)	$1,200 - $1,300

Margin from purchased commodities ($ millions) (1)	$50 - $65
Electricity revenue net of electricity generation expenses ($ millions)	$20 - $40


Other operating expenses net of other revenue ($ millions) (2)	$135 - $145		$20 - $30
Transportation costs ($ millions)	$115 - $125	$75 - $85
Taxes other than on income ($ millions)	$272 - $282	$240 - $246
Interest and debt expense ($ millions)	$115 - $125

Other Assumptions:
Brent ($/Bbl)	$84.51
NYMEX ($/Mcf)	$3.55
Price realization oil - % of Brent:	92% - 96%
Price realization NGLs - % of Brent:	52% - 57%
Price realization natural gas - % of NYMEX:	80% - 85%

Current income tax provision ($ millions) (3)	$(2) - $2
Effective tax rate	33% - 37%

(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.

(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


	3Q26E
	Consolidated				Oil and Natural Gas Segment				Carbon Management Segment
($ millions)	Low		High		Low		High		Low		High
General and administrative expenses	$	82	$	92	$	12	$	16	$	—	$	2
Equity-settled stock-based compensation	(7)		(7)		—		—		—		—

Estimated adjusted general and administrative expenses	$	75	$	85	$	12	$	16	$	—	$	2



	Consolidated
	3Q26E
($ millions)	Low		High
Revenue from marketing of purchased commodities	$	32	$	48
Costs related to marketing of purchased commodities	(21)		(33)
Margin from purchased commodities	$	11	$	15

Page 12



	Consolidated
	3Q26E
($ millions)	Low		High
Other operating expenses, net	$	23	$	39
Other revenue	(3)		(7)
Other operating expenses net of other revenue	$	20	$	32


	2026E
	Consolidated				Oil and Natural Gas Segment				Carbon Management Segment
($ millions)	Low		High		Low		High		Low		High
General and administrative expenses	$	365	$	385	$	51	$	63	$	4	$	10
Equity-settled stock-based compensation	(30)		(35)		—		—		—		—

Estimated adjusted general and administrative expenses	$	335	$	350	$	51	$	63	$	4	$	10



	Consolidated
	2026E
($ millions)	Low		High
Revenue from marketing of purchased commodities	$	138	$	163
Costs related to marketing of purchased commodities	(88)		(98)
Margin from purchased commodities	$	50	$	65



	Consolidated
	2026E
($ millions)	Low		High
Other operating expenses, net	$	156	$	174
Other revenue	(21)		(29)
Other operating expenses net of other revenue	$	135	$	145

Page 13

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.

	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions, except per share amounts)	2026		2026		2025		2026		2025
Net income (loss)	$	514	$	(711)	$	172	$	(197)	$	287
Unusual, infrequent and other items:
Non-cash derivative (gain) loss on Brent based commodity contracts	(370)		792		(140)		422		(162)
Non-cash derivative (gain) loss on natural gas derivative contracts	(20)		12		—		(8)		—



Severance and termination costs	—		25		6		25		8
Merger-related costs	1		1		—		2		3


Loss on early extinguishment of debt	28		21		—		49		1

Offshore platform expense	10		10		—		20		—
Litigation and settlements	—		—		25		—		25
Measurement period adjustments, net	(2)		—		—		(2)		1
Other, net	12		8		6		20		(3)
Total unusual, infrequent and other items	(341)		869		(103)		528		(127)
Income tax (benefit) provision of adjustments at the combined tax rate	(85)		(79)		29		(164)		36


Adjusted net income	$	88	$	79	$	98	$	167	$	196

Net income (loss) per share – basic	$	5.79	$	(8.02)	$	1.93	$	(2.22)	$	3.20
Net income (loss) per share – diluted	$	5.76	$	(8.02)	$	1.92	$	(2.22)	$	3.18
Adjusted net income per share – basic	$	0.99	$	0.89	$	1.10	$	1.88	$	2.18
Adjusted net income per share – diluted	$	0.99	$	0.88	$	1.10	$	1.87	$	2.17

Page 14


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.

	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions, except per BOE amounts)	2026		2026		2025		2026		2025
Net (loss) income	$	514	$	(711)	$	172	$	(197)	$	287
Interest and debt expense	28		29		25		57		52
Depreciation, depletion and amortization	131		133		128		264		259
Income tax (benefit) provision	(56)		(49)		70		(105)		117
Interest income	—		(1)		(2)		(1)		(5)
Equity loss from unconsolidated subsidiaries	2		2		—		4		1
Exploration expense	27		—		1		27		1
Unusual, infrequent and other items (1)	(341)		869		(103)		528		(127)
Non-cash items
Accretion expense	27		27		28		54		57
Stock-based compensation	8		7		7		15		13

Pension and post-retirement benefits	(2)		(2)		(2)		(4)		(3)

Adjusted EBITDAX	$	338	$	304	$	324	$	642	$	652

Net cash provided by operating activities	$	263	$	99	$	165	$	362	$	351
Cash interest payments	26		1		39		27		50
Cash interest received	—		(1)		(2)		(1)		(5)
Cash income taxes	16		—		39		16		39
Exploration expense	27		—		1		27		1
Working capital changes	6		205		82		211		216

Adjusted EBITDAX	$	338	$	304	$	324	$	642	$	652

Net (loss) income per Boe	$	37.93	$	(51.19)	$	13.78	$	(7.18)	$	11.42
Adjusted EBITDAX per Boe	$	24.94	$	21.89	$	25.95	$	23.40	$	25.93

(1) See Adjusted Net Income (Loss) reconciliation.

Page 15


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	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions)	2026		2026		2025		2026		2025
Segment profit	$	427	$	281	$	194	$	711	$	460

Depreciation, depletion and amortization	124		128		121		251		247
Exploration expense	27		—		1		27		1
Accretion expense	27		27		28		54		57
Adjusted income items	3		3		2		7		3






Adjusted EBITDAX - Oil and Natural Gas	$	608	$	439	$	346	$	1,050	$	768

Carbon Management Segment
Segment loss	$	(13)	$	(12)	$	(20)	$	(25)	$	(45)
Interest on contingent liability (related to Carbon TerraVault JV)	3		3		2		6		5
Equity loss from unconsolidated subsidiary	2		1		1		3		2


Adjusted EBITDAX - Carbon Management	$	(8)	$	(8)	$	(17)	$	(16)	$	(38)


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.

	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions)	2026		2026		2025		2026		2025



Net cash provided by operating activities	$	263	$	99	$	165	$	362	$	351
Capital investments	(149)		(131)		(56)		(280)		(111)
Free cash flow	$	114	$	(32)	$	109	$	82	$	240


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.

	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions)	2026		2026		2025		2026		2025

Net cash provided by operating activities	$	263	$	99	$	165	$	362	$	351
Net changes in operating assets and liabilities	37		148		56		185		122
Net cash provided by operating activities before net changes in operating assets and liabilities	300		247		221		$	547	$	473
Capital investments	(149)		(131)		(56)		(280)		(111)
Free cash flow before net changes in operating assets and liabilities	$	151	$	116	$	165	$	267	$	362

Page 16


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.

	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions)	2026		2026		2025		2026		2025
General and administrative expenses	$	97	$	106	$	79	$	203	$	151
Stock-based compensation	(8)		(7)		(7)		(15)		(13)




Adjusted G&A expenses	$	89	$	99	$	72	$	188	$	138




G&A per BOE	$	7.16	$	7.63	$	6.33	$	7.40	$	6.01
Adjusted G&A per BOE	$	6.57	$	7.13	$	5.77	$	6.85	$	5.49


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.

	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions)	2026		2026		2025		2026		2025
Total operating revenues	$	1,297	$	119	$	978	$	1,416	$	1,890
Less: Net gain (loss) from commodity derivatives	205		(848)		157		(643)		163
Total operating revenues before net gain (loss) from commodity derivatives	$	1,092	$	967	$	821	$	2,059	$	1,727


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.

	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions)	2026		2026		2025		2026		2025
Revenue from purchased commodities	$	26	$	41	$	56	$	67	$	120
Costs related to purchased commodities	(15)		(23)		(41)		(38)		(91)
Margin from purchased commodities	$	11	$	18	$	15	$	29	$	29


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.

	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions)	2026		2026		2025		2026		2025
Electricity revenue	$	6	$	11	$	58	$	17	$	80
Electricity generation expenses	(10)		(5)		(5)		(15)		(15)
Electricity revenue net of electricity generation expenses	$	(4)	$	6	$	53	$	2	$	65

Page 17


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.

	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
($ millions)	2026		2026		2025		2026		2025
Other operating expenses, net	$	60	$	54	$	65	$	114	$	98
Other revenue	(4)		(10)		(5)		(14)		(11)
Other operating expenses net of other revenue	$	56	$	44	$	60	$	100	$	87

Page 18


Attachment 4
PRODUCTION STATISTICS

	2nd Quarter	1st Quarter	2nd Quarter	Six Months	Six Months
Net Production Per Day	2026	2026	2025	2026	2025

Oil (MBbl/d)
San Joaquin Basin	93	96	83	94	84
Los Angeles Basin	15	17	17	16	17
Uinta Basin	3	3	—	3	—
Other Basins	9	8	9	9	9
Total	120	124	109	122	110

NGLs (MBbl/d)
San Joaquin Basin	10	10	10	10	10

Total	10	10	10	10	10

Natural Gas (MMcf/d)
San Joaquin Basin	93	95	96	95	99
Los Angeles Basin	1	1	1	1	1
Sacramento Basin	10	10	12	10	12
Uinta Basin	9	8	—	9	—
Other Basins	2	3	2	2	2
Total	115	117	111	117	114

Total Net Production (MBoe/d)	149	154	137	152	139





Gross Operated and Net Non-Operated	2nd Quarter	1st Quarter	2nd Quarter	Six Months	Six Months
Production Per Day	2026	2026	2025	2026	2025

Oil (MBbl/d)
San Joaquin Basin	102	103	89	102	90
Los Angeles Basin	21	21	21	21	21
Uinta Basin	4	4	—	4	—
Other Basins	9	9	11	10	11
Total	136	137	121	137	122

NGLs (MBbl/d)
San Joaquin Basin	10	10	11	10	11
Uinta Basin	1	—	—	1	—
Other Basins	—	1	—	—	—
Total	11	11	11	11	11

Natural Gas (MMcf/d)
San Joaquin Basin	128	127	134	128	134
Los Angeles Basin	6	6	6	6	6
Sacramento Basin	13	13	14	13	15
Uinta Basin	12	11	—	11	—
Other Basins	3	3	4	3	3
Total	162	160	158	161	158

Total Gross Production (MBoe/d)	174	175	158	175	159

Page 19


Attachment 5
PRICE STATISTICS
	2nd Quarter			1st Quarter			2nd Quarter			Six Months			Six Months
	2026			2026			2025			2026			2025
Oil ($ per Bbl)
Realized price with derivative settlements	$	76.43		$	69.37		$	66.73		$	72.88		$	69.39
Realized price without derivative settlements	$	91.55		$	74.53		$	65.07		$	82.97		$	69.34

NGLs ($/Bbl)	$	49.62		$	44.98		$	42.41		$	47.29		$	48.60

Natural gas ($/Mcf)

Realized price without derivative settlements	$	1.84		$	3.56		$	2.79		$	2.72		$	3.46

Index Prices
Brent oil ($/Bbl)	$	96.87		$	77.90		$	66.76		$	87.38		$	70.84
WTI oil ($/Bbl)	$	92.79		$	71.93		$	63.74		$	82.36		$	67.58
NYMEX average monthly settled price ($/MMBtu)	$	2.90		$	5.04		$	3.44		$	3.97		$	3.55

Realized Prices as Percentage of Index Prices
Oil with derivative settlements as a percentage of Brent	79		%	89		%	100		%	83		%	98		%
Oil without derivative settlements as a percentage of Brent	95		%	96		%	97		%	95		%	98		%

Oil with derivative settlements as a percentage of WTI	82		%	96		%	105		%	88		%	103		%
Oil without derivative settlements as a percentage of WTI	99		%	104		%	102		%	101		%	103		%

NGLs as a percentage of Brent	51		%	58		%	64		%	54		%	69		%
NGLs as a percentage of WTI	53		%	63		%	67		%	57		%	72		%

Natural gas with derivative settlements as a percentage of NYMEX contract month average	63		%	71		%	81		%	69		%	97		%

Natural gas without derivative settlements as a percentage of NYMEX contract month average	63		%	71		%	81		%	69		%	97		%

Page 20


Attachment 6
SECOND QUARTER 2026 DRILLING ACTIVITY
	San Joaquin	Los Angeles	Sacramento	Uinta	Other
Wells Drilled	Basin	Basin	Basin	Basin	Basins	Total

Development Wells
Primary	22	1	—	1	—	24
Waterflood	33	1	—	—	—	34
Steamflood	39	—	—	—	—	39








Total (1)	94	2	—	1	—	97












(1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled.

Page 21