California Resources Reports Second Quarter 2024 Financial and Operating Results

Increasing quarterly dividend by 25%, enhancing cash returns to shareholders

Targeting $235 million in Aera merger synergies

New EPA Class VI permit application to expand Company's carbon platform, doubling Central California CO₂ potential storage capacity

LONG BEACH, Calif.--(BUSINESS WIRE)--California Resources Corporation (NYSE: CRC) today reported financial and operating results for the second quarter of 2024. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Wednesday, August 7, 2024. Participation details can be found within this release. In addition, supplemental slides have been posted to CRC’s website at www.crc.com.

Highlights:

Aera Merger

• Successfully closed the merger with Aera Energy on July 1, 2024. Complementary assets grow Company's core base, expected to double cash flow, and adds quality assets to carbon business platform
• Increased Aera merger targeted synergies to $235 million which includes a reduction of $60 million¹ in annual interest expense and $25 million in additional operational synergies

CRC

• Enhanced cash returns to shareholders through 25% increase in quarterly dividend; declared quarterly dividend of $0.3875/share to be paid in the third quarter of 2024
• Generated $97 million of net cash provided by operating activities, net cash provided by operating activities before changes in operating assets and liabilities² of $108 million and $63 million of free cash flow²
• Returned 142% of year-to-date free cash flow², or $136 million, to shareholders including $93 million in share repurchases and $43 million in dividends
• Generated $8 million of net income, $42 million of adjusted net income² and adjusted EBITDAX² of $139 million
• Delivered second quarter average net production of 76 MBoe/d and average net oil production of 47 thousand barrels of oil per day (MBo/d). Gross production averaged 93 MBoe/d
• Exceeded first half 2024 production expectations through lower-than-expected natural field declines and in-line capital investments; entry-to-exit gross production declined by 2%, or 2 thousand barrels of oil equivalent per day (MBoe/d) on drilling and workover capital investments of $51 million
• Submitted a 102 million metric ton (MMT) Class VI permit application to the EPA for the Carbon TerraVault VI (CTV VI) CO₂ reservoir in Central California bringing CTV's total potential storage capacity with Class VI permits submitted to the EPA to ~320 MMT. See CTV's Second Quarter 2024 Update for additional information

"These are exciting times for CRC as we successfully closed the merger with Aera Energy in early July," said Francisco Leon, CRC's President and Chief Executive Officer. "I am pleased with the CRC team's execution in the second quarter and we are working diligently with our new Aera colleagues on executing a comprehensive integration plan. We continue to identify additional avenues to further enhance shareholder value and accelerate momentum across our E&P and carbon management businesses. We are committed to improving CRC’s cash flows and remain vigilant in our environmental stewardship. With the addition of Aera, we believe we are extremely well positioned in the years ahead to provide substantial value to CRC shareholders and stakeholders."

Second Quarter 2024 Financial and Operating Summary

CRC reported net income of $8 million, or $0.11 per fully diluted share of common stock, and adjusted net income² of $42 million, or $0.60 per fully diluted share. Net cash provided by operating activities was $97 million.

Gross production averaged 93 MBoe/d and net production averaged 76 MBoe/d, including net oil production of 47 MBo/d. Second quarter net production was negatively impacted by approximately 3 Mboe/d due to both scheduled maintenance and unplanned downtime at CRC's Elk Hills power plant. Average realized oil prices were 98% of Brent.

Operating costs declined 11% quarter-over-quarter to $156 million. The decrease was primarily related to lower activity and natural gas prices, as well as vendor cost savings.

Capital investments totaled $34 million, below guidance, primarily due to a $14 million change from capital to expense related to the Elk Hills power plant turnaround which began in the first quarter of 2024 and continued into the second quarter of 2024.

Second Quarter 2024 Financial Results

Selected Production, Price Information and Results of Operations	2nd Quarter			1st Quarter
($ in millions)		2024			2024
Average net oil production per day (MBbl/d)		47			48
Realized oil price with derivative settlements ($ per Bbl)	$	81.29		$	77.17
Average net NGL production per day (MBbl/d)		10			11
Realized NGL price ($ per Bbl)	$	46.96		$	50.5
Average net natural gas production per day (Mmcf/d)		114			105
Realized natural gas price with derivative settlements ($ per Mcf)	$	1.78		$	3.9
Average net total production per day (MBoe/d)		76			76
Margin from marketing of purchased commodities^4 ($ millions)	$	8		$	20
Margin from electricity sales^5 ($ millions)	$	22		$	7
Net gain (loss) from oil commodity derivatives ($ millions)	$	5		$	(71	)
Selected Financial Statement Data and non-GAAP measures:	2nd Quarter			1st Quarter
($ and shares in millions, except per share amounts)		2024			2024
Statements of Operations:
Revenues
Total operating revenues	$	514		$	454
Selected Expenses
Operating costs	$	156		$	176
General and administrative expenses	$	63		$	57
Adjusted general and administrative expenses^2	$	56		$	49
Taxes other than on income	$	39		$	38
Transportation costs	$	17		$	20
Operating Income (loss)	$	38		$	(4	)
Interest and debt expense	$	(17	)	$	(13	)
Income tax benefit (provision)	$	(3	)	$	9
Net (loss) Income	$	8		$	(10	)
EPS, Non-GAAP Measures and Select Balance Sheet Data
Adjusted net income^2	$	42		$	54
Weighted-average common shares outstanding - diluted		70.0			69.0
Net loss (income) per share - diluted	$	0.11		$	(0.14	)
Adjusted net income^2 per share - diluted	$	0.60		$	0.75
Adjusted EBITDAX^2	$	139		$	149
Net cash provided by operating activities	$	97		$	87
Net cash provided by operating activities before changes in operating assets and liabilities, net^2	$	108		$	92
Capital investments	$	34		$	54
Free cash flow^2	$	63		$	33
Cash and cash equivalents	$	1,031			403

Guidance

The following tables reflect guidance for key third quarter and second half 2024 financial and operating results. Guidance for the second half of 2024 includes approximately $30 million in targeted Aera merger synergies and reflects $60 million of interest savings achieved at merger close. In the second half of 2024, CRC expects to run a one rig program under its existing permits. See Attachment 2 for more information on CRC's third quarter and second half 2024 guidance.

CRC GUIDANCE^3	Total 3Q24E
Net Production (MBoe/d)	141 - 145
Oil Production (%)	~79%
Capital ($ millions)	$90 - $110
Adjusted EBITDAX^2 ($ millions)	$375 - $415

CRC GUIDANCE^3	Total 2H24E
Net Production (MBoe/d)	140 - 146
Oil Production (%)	~79%
Capital ($ millions)	$170 - $210
Adjusted EBITDAX^2	$720 - $760

Shareholder Returns

CRC is committed to returning cash to shareholders through dividends and repurchases of common stock.

During the second quarter of 2024, CRC repurchased 0.7 million shares for $35 million at an average price of $49.71 per share. Since the inception of the Share Repurchase Program in May 2021 through June 30, 2024, 16.6 million shares have been repurchased for $697 million at an average price of $41.74 per share.

On August 2, 2024, CRC's Board of Directors amended the cash dividend policy to increase the total annual dividend to $1.55 per share of common stock, payable to shareholders in quarterly increments of $0.3875 per share. This represents a 25% increase to the prior dividend policy.

On August 5, 2024, CRC's Board of Directors declared a quarterly cash dividend of $0.3875 per share of common stock. The dividend is payable to shareholders of record on August 30, 2024 and will be paid on September 16, 2024.

From October 2020 through June 30, 2024, CRC has returned $949 million of cash to its stakeholders, including $697 million in share repurchases, $55 million in principal of its 2026 Senior Notes repurchases and $197 million of dividends.

Balance Sheet and Liquidity

On June 5, 2024, CRC completed an offering of $600 million in an aggregate principal amount of 8.25% senior notes due 2029 (2029 Senior Notes). The net proceeds from this offering plus available cash were used to repay all Aera’s outstanding debt at the close of the Aera merger on July 1, 2024. This reduced the combined companies annual interest payments by $60 million.

As of June 30, 2024, CRC had liquidity of $1.5 billion, which consisted of $1.0 billion in available cash and cash equivalents plus $600 million of available borrowing capacity under its Revolving Credit Facility, which is after $30 million outstanding on the Revolving Credit Facility, less $130 million of outstanding letters of credit.

On July 1, 2024, CRC amended its Revolving Credit Facility which increased the aggregate commitment to $1.1 billion from $630 million and increased its borrowing base to $1.5 billion from $1.2 billion. CRC had $1,005 million of liquidity at the close of the Aera merger. There were no amounts drawn on the Revolving Credit Facility as of August 2, 2024.

Upcoming Investor Conference Participation

CRC plans to participate in the following events in September 2024:

• 2024 Barclays CEO Energy-Power Conference on September 3 to 5 in New York, NY
• NYSE Energy Virtual Investor Access Day on September 10
• Pickering Energy Partners Energy Conference 2024 on September 16 to 18 in Austin, TX
• 2024 Goldman Sachs Global Sustainability Forum on September 26 in New York, NY

CRC’s presentation materials will be available the day of the events on the Events and Presentations page in the Investor Relations section on www.crc.com.

Conference Call Details

A conference call is scheduled for 1 p.m. ET (10 a.m. PT) on Wednesday, August 7, 2024. To participate in the call, dial [phone] (International calls please dial [phone]) or access via webcast at www.crc.com. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10189857/fcb0ff718c. A digital replay of the conference call will be archived for approximately 90 days and supplemental slides will be available online in the Investor Relations section of www.crc.com.

^1As of June 30, 2024. When accounting for estimated cash interest income, CRC’s net interest savings were ~$36 million.

^2See Attachment 3 for the non-GAAP financial measures of operating costs per BOE (excluding effects of PSCs), adjusted net income (loss), adjusted net income (loss) per share - basic and diluted, net cash provided by operating activities before changes in operating assets and liabilities, net, adjusted EBITDAX, free cash flow and adjusted general and administrative expenses, including reconciliations to their most directly comparable GAAP measure, where applicable. For the 3Q24 estimates of the non-GAAP measures of adjusted EBITDAX and adjusted general and administrative expenses, including reconciliations to its most directly comparable GAAP measure, see Attachment 2.

^3 2H24 guidance assumes Brent price of $83.29 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.86 per mcf. 3Q24 guidance assumes Brent price of $84.23 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.61 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.

^4Margin from Marketing of Purchased Commodities is calculated as the difference between Revenue from Marketing of Purchased Commodities and Costs Related to Marketing of Purchased Commodities

^5Electricity Margin is calculated as the difference between Electricity Sales and Electricity Generation Expenses

About California Resources Corporation

California Resources Corporation (CRC) is an independent energy and carbon management company committed to 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 carbon capture and storage (CCS) and other emissions-reducing projects. For more information about CRC, please visit www.crc.com.

About Carbon TerraVault

Carbon TerraVault Holdings, LLC (CTV), a subsidiary of CRC, is developing services that include the capture, transport and storage of carbon dioxide for its customers. Through its subsidiaries, CTV is developing a series of proposed CCS projects to inject CO₂ captured from industrial sources into depleted underground reservoirs for permanent storage deep underground. For more information about CTV, please visit www.carbonterravault.com.

Forward-Looking Statements

This document contains statements that CRC believes to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding CRC's future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as “expect,” “could,” “may,” “anticipate,” “intend,” “plan,” “ability,” “believe,” “seek,” “see,” “will,” “would,” “estimate,” “forecast,” “target,” “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

Although 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 include:

• fluctuations in commodity prices, including supply and demand considerations for CRC's products and services, and the impact of such fluctuations on revenues and operating expenses;
• decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods;
• government policy, war and political conditions and events, including the military conflicts in Israel, Ukraine and Yemen and the Red Sea;
• the ability to successfully integrate Aera's business;
• regulatory actions and changes that affect the oil and gas industry generally and CRC in particular, including (1) the availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities or its carbon management business; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of CRC's products;
• the impact of inflation on future expenses and changes generally in the prices of goods and services;
• changes in business strategy and CRC's capital plan;
• lower-than-expected production or higher-than-expected production decline rates;
• changes to CRC's estimates of reserves and related future cash flows, including changes arising from its inability to develop such reserves in a timely manner, and any inability to replace such reserves;
• the recoverability of resources and unexpected geologic conditions;
• general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets;
• production-sharing contracts' effects on production and operating costs;
• the lack of available equipment, service or labor price inflation;
• limitations on transportation or storage capacity and the need to shut-in wells;
• any failure of risk management;
• results from operations and competition in the industries in which CRC operates;
• CRC's ability to realize the anticipated benefits from prior or future efforts to reduce costs;
• environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions);
• the creditworthiness and performance of CRC's counterparties, including financial institutions, operating partners, CCS project participants and other parties;
• reorganization or restructuring of CRC's operations;
• CRC's ability to claim and utilize tax credits or other incentives in connection with its CCS projects;
• CRC's ability to realize the benefits contemplated by its energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;
• CRC's ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and its ability to convert its CDMAs to definitive agreements and enter into other offtake agreements;
• CRC's ability to maximize the value of its carbon management business and operate it on a stand alone basis;
• CRC's ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;
• uncertainty around the accounting of emissions and its ability to successfully gather and verify emissions data and other environmental impacts;
• changes to CRC's dividend policy and share repurchase program, and its ability to declare future dividends or repurchase shares under its debt agreements;
• limitations on CRC's financial flexibility due to existing and future debt;
• insufficient cash flow to fund CRC's capital plan and other planned investments and return capital to shareholders;
• changes in interest rates;
• CRC's access to and the terms of credit in commercial banking and capital markets, including its ability to refinance its debt or obtain separate financing for its carbon management business;
• changes in state, federal or international tax rates, including CRC's ability to utilize its net operating loss carryforwards to reduce its income tax obligations;
• effects of hedging transactions;
• the effect of CRC's stock price on costs associated with incentive compensation;
• inability to enter into desirable transactions, including joint ventures, divestitures of oil and natural gas properties and real estate, and acquisitions, and CRC's ability to achieve any expected synergies;
• disruptions due to earthquakes, forest fires, floods, extreme weather events or other natural occurrences, accidents, mechanical failures, power outages, transportation or storage constraints, labor difficulties, cybersecurity breaches or attacks or other catastrophic events;
• pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19 pandemic; and
• other factors discussed in Part I, Item 1A – Risk Factors in CRC's Annual Report on Form 10-K and its other SEC filings available at www.crc.com.

CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and it undertakes no obligation to update this information. This document may also contain information from third party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and does not warrant the accuracy or completeness of such third-party information.

Attachment 1
SUMMARY OF RESULTS
	2nd Quarter			1st Quarter			2nd Quarter			Six Months			Six Months
($ and shares in millions, except per share amounts)		2024			2024			2023			2024			2023
Statements of Operations:
Revenues
Oil, natural gas and NGL sales	$	412		$	429		$	447		$	841		$	1,162
Net gain (loss) from commodity derivatives		5			(71	)		31			(66	)		73
Revenue from marketing of purchased commodities		51			74			72			125			259
Electricity sales		36			15			34			51			102
Other revenue		10			7			7			17			19
Total operating revenues		514			454			591			968			1,615
Operating Expenses
Operating costs		156			176			186			332			440
General and administrative expenses		63			57			71			120			136
Depreciation, depletion and amortization		53			53			56			106			114
Asset impairment		13			—			—			13			3
Taxes other than on income		39			38			42			77			84
Exploration expense		—			1			1			1			2
Costs related to marketing of purchased commodities		43			54			27			97			151
Electricity generation expenses		14			8			13			22			62
Transportation costs		17			20			16			37			33
Accretion expense		13			12			11			25			23
Carbon management business expenses		15			8			8			23			13
Other operating expenses, net		51			37			13			88			21
Total operating expenses		477			464			444			941			1,082
Net gain on asset divestitures		1			6			—			7			7
Operating Income (Loss)		38			(4	)		147			34			540
Non-Operating (Expenses) Income
Interest and debt expense		(17	)		(13	)		(14	)		(30	)		(28	)
Loss from investment in unconsolidated subsidiary		(4	)		(3	)		(1	)		(7	)		(3	)
Other non-operating (loss) income, net		(6	)		1			3			(5	)		2
Income Before Income Taxes		11			(19	)		135			(8	)		511
Income tax (provision) benefit		(3	)		9			(38	)		6			(113	)
Net Income	$	8		$	(10	)	$	97		$	(2	)	$	398
Net income (loss) per share - basic	$	0.12		$	(0.14	)	$	1.39		$	(0.03	)	$	5.65
Net income (loss) per share - diluted	$	0.11		$	(0.14	)	$	1.35		$	(0.03	)	$	5.47
Adjusted net income	$	42		$	54		$	38		$	96		$	231
Adjusted net income per share - basic	$	0.62		$	0.78		$	0.55		$	1.40		$	3.28
Adjusted net income per share - diluted	$	0.60		$	0.75		$	0.53		$	1.35		$	3.18
Weighted-average common shares outstanding - basic		68.1			69.0			69.7			68.6			70.5
Weighted-average common shares outstanding - diluted		70.0			69.0			71.9			68.6			72.7
Adjusted EBITDAX	$	139		$	149		$	138		$	288		$	496
Effective tax rate		27	%		45	%		28	%		75	%		22	%
	2nd Quarter			1st Quarter			2nd Quarter			YTD June			YTD June
($ in millions)		2024			2024			2023			2024			2023
Cash Flow Data:
Net cash provided by operating activities	$	97		$	87		$	108		$	184		$	418
Net cash used in investing activities	$	(33	)	$	(49	)	$	(44	)	$	(82	)	$	(105	)
Net cash provided (used) in financing activities	$	564		$	(131	)	$	(93	)	$	433		$	(172	)
	June 30 ,			December 31,
($ in millions)		2024			2023
Selected Balance Sheet Data:
Total current assets	$	1,439		$	929
Property, plant and equipment, net	$	2,773		$	2,770
Deferred tax asset	$	139		$	132
Total current liabilities	$	593		$	616
Long-term debt, net	$	1,161		$	540
Noncurrent asset retirement obligations	$	436		$	422
Stockholders' Equity	$	2,052		$	2,219

GAINS AND LOSSES FROM COMMODITY DERIVATIVES
	2nd Quarter			1st Quarter			2nd Quarter			YTD June			YTD June
($ millions)		2024			2024			2023			2024			2023
Non-cash derivative gain (loss)	$	11		$	(59	)	$	94		$	(48	)	$	201
Net payments on settled commodity derivatives		(6	)		(12	)		(63	)		(18	)		(128	)
Net gain (loss) from commodity derivatives	$	5		$	(71	)	$	31		$	(66	)	$	73

CAPITAL INVESTMENTS
	2nd Quarter			1st Quarter		2nd Quarter		YTD June		YTD June
($ millions)	2024			2024		2023		2024		2023
Facilities ^(1)	$	17		$	14	$	11	$	31	$	20
Drilling		18			15		13		33		38
Workovers		11			7		11		18		17
Total E&P capital		46			36		35		82		75
CMB ^(1)		(2	)		4		—		2		1
Corporate and other		(10	)		14		4		4		10
Total capital program	$	34		$	54	$	39	$	88	$	86
^(1)Facilities capital includes $0, $0 and $1 million in the second and first quarter of 2024 and second quarter of 2023, respectively, and $0 and $2 million for the six months 2024 and 2023, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this Earnings Release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital.
Capital for the three months ended June 30, 2024 reflects a $3 million reclassification from capital (PP&E) to expense for engineering costs incurred during the two prior quarters. Before this reclassification, CMB capital was $1 million for the three months ended June 30, 2024. Capital for Corporate and other for the three months ended June 30, 2024 reflects a reclassification of $10 million from capital (PP&E) to expense for planned major maintenance in the first quarter of 2024. Before the reclassifications, Corporate and other capital for the three months would have been $14 million.

Attachment 2
CRC GUIDANCE	Total 2H24E	CMB 2H24E	E&P, Corp. & Other 2H24E
Net Production (MBoe/d)	140 - 146		140 - 146
Oil Production (%)	~79%		~79%
CMB Expenses & Operating Costs ($ millions)	$675 - $720	$35 - $40	$640 - $680
General and Administrative Expenses ($ millions)	$190 - $210	$3 - $5	$187 - $205
Adjusted General and Administrative Expenses ($ millions)	$165 - $185	$2 - $4	$163 - $181
Capital ($ millions)	$170 - $210	$10 - $15	$160 - $195
Drilling & completions, workover ($ millions)	$85 - $105
Facilities ($ millions)	$70 - $80
Carbon management business ($ millions)	$10- $15
Corporate & other ($ millions)	$5 - $10
Adjusted EBITDAX ($ millions)	$720 - $760
Margin from Marketing of Purchased Commodities ($ millions) ^(1)	$24 - $30		$24 - $30
Electricity Margin ($ millions) ^(2)	$65 - $80		$65 - $80
Other Operating Revenue & Expenses, net ($ millions)^(3)	($100) - ($105)		($100) - ($105)
Transportation Costs ($ millions)	$40 - $50		$40 - $50
Taxes Other Than on Income ($ millions)	$150 - $160		$150 - $160
Interest and Debt Expense ($ millions)	$53 - $59		$53 - $59
Commodity Assumptions:
Brent ($/Bbl)	$83.29		$83.29
NYMEX ($/Mcf)	$2.86		$2.86
Oil - % of Brent:	94% to 98%		94% to 98%
NGL - % of Brent:	52% to 58%		52% to 58%
Natural Gas - % of NYMEX:	110% to 131%		110% to 131%

CRC GUIDANCE	Total 3Q24E	CMB 3Q24E	E&P, Corp. & Other 3Q24E
Net Production (MBoe/d)	141 - 145		141 - 145
Oil Production (%)	~79%		~79%
CMB Expenses & Operating Costs ($ millions)	$325 - $355	$15 - $20	$310 - $335
General and Administrative Expenses ($ millions)	$100 - $120	$2 - $4	$98 - $116
Adjusted General and Administrative Expenses ($ millions)	$80 - $99	$1 - $2	$79 - $97
Capital ($ millions)	$90 - $110	$5 - $10	$85 - $100
Drilling & completions, workover ($ millions)	$46 - $55
Facilities ($ millions)	$37 - $42
Carbon management business ($ millions)	$5- $9
Corporate & other ($ millions)	$2 - $4
Adjusted EBITDAX ($ millions)	$375 - $415
Margin from Marketing of Purchased Commodities ($ millions) ^(1)	$10 - $16		$10 - $16
Electricity Margin ($ millions) ^(2)	$45 - $65		$45 - $65
Other Operating Revenue & Expenses, net ($ millions)^(3)	($100) - ($112)		($100) - ($112)
Transportation Costs ($ millions)	$20 - $25		$20 - $25
Taxes Other Than on Income ($ millions)	$75 - $85		$75 - $85
Interest and Debt Expense ($ millions)	$25 - $30		$25 - $30
Commodity Assumptions:
Brent ($/Bbl)	$84.23		$84.23
NYMEX ($/Mcf)	$2.61		$2.61
Oil - % of Brent:	94% - 98%		94% - 98%
NGL - % of Brent:	46% - 54%		46% - 54%
Natural Gas - % of NYMEX:	100% - 114%		100% - 114%
^(1)Margin from Marketing of Purchased Commodities is calculated as the difference between Revenue from Marketing of Purchased Commodities and Costs Related to Marketing of Purchased Commodities.
^(2)Electricity Margin is calculated as the difference between Electricity Sales and Electricity Generation Expenses.
^(3)Other Operating Revenue & Expenses, net is calculated as the difference between Other Revenue and Other Operating Expenses, net. Includes Aera merger and integration costs paid in 3Q24 and $60 million of costs to achieve that we expect to be paid in 4Q24.
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.

ESTIMATED ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES RECONCILIATION
	2H24 Estimated
	Consolidated						CMB						E&P, Corporate & Other
($ millions)	Low			High			Low			High			Low			High
General and administrative expenses	$	190		$	210		$	3		$	5		$	187		$	205
Equity-settled stock-based compensation		(23	)		(23	)		(1	)		(1	)		(22	)		(22	)
Other		(2	)		(2	)								(2	)		(2	)
Estimated adjusted general and administrative expenses	$	165		$	185		$	2		$	4		$	163		$	181

	3Q24 Estimated
	Consolidated						CMB						E&P, Corporate & Other
($ millions)	Low			High			Low			High			Low			High
General and administrative expenses	$	100		$	120		$	2		$	4		$	98		$	116
Equity-settled stock-based compensation		(19	)		(20	)		(1	)		(2	)		(18	)		(18	)
Other		(1	)		(1	)								(1	)		(1	)
Estimated adjusted general and administrative expenses	$	80		$	99		$	1		$	2		$	79		$	97

ESTIMATED ADJUSTED EBITDAX RECONCILIATION
	2H24E
($ millions)	Low		High
Net income	$	152	$	162
Interest and debt expense, net		53		58
Depreciation, depletion and amortization		310		315
Income taxes		55		62
Unusual, infrequent and other items		83		88
Other non-cash items
Accretion expense		54		58
Stock-settled compensation		10		14
Post-retirement medical and pension		3		3
Estimated adjusted EBITDAX	$	720	$	760
Net cash provided by operating activities	$	480	$	500
Cash interest		48		54
Cash income taxes		58		66
Working capital changes		134		140
Estimated adjusted EBITDAX	$	720	$	760

	3Q24E
($ millions)	Low		High
Net income	$	45	$	65
Interest and debt expense, net		25		29
Depreciation, depletion and amortization		156		160
Income taxes		16		20
Unusual, infrequent and other items		102		106
Other non-cash items
Accretion expense		26		28
Stock-settled compensation		5		7
Post-retirement medical and pension		0		0
Estimated adjusted EBITDAX	$	375	$	415
Net cash provided by operating activities	$	270	$	290
Cash interest		19		23
Cash income taxes		27		31
Working capital changes		59		71
Estimated adjusted EBITDAX	$	375	$	415

Attachment 3

NON-GAAP FINANCIAL MEASURES AND 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. The non-GAAP measures include adjusted net income (loss), adjusted EBITDAX, E&P, Corporate & Other adjusted EBITDAX, CMB adjusted EBITDAX, net cash provided by operating activities before changes in operating assets and liabilities, net, free cash flow, E&P, Corporate & Other free cash flow, CMB free cash flow, adjusted general and administrative expenses, operating costs per BOE, and adjusted total capital among others. 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 the non-GAAP measures reported in this earnings release, 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 measure of adjusted net income and adjusted net income per share.
	2nd Quarter			1st Quarter			2nd Quarter			YTD June			YTD June
($ millions, except per share amounts)		2024			2024			2023			2024			2023
Net income (loss)	$	8		$	(10	)	$	97		$	(2	)	$	398
Unusual, infrequent and other items:
Non-cash derivative (gain) loss		(11	)		59			(94	)		48			(201	)
Asset impairment		13			—			—			13			3
Severance and termination costs		1			—			2			1			3
Aera merger transaction fees		5			10			—			15			—
Aera merger integration fees		8			3			—			11			—
Increased power and fuel costs due to power plant shutdown		15			21			—			36			—
Net gain on asset divestitures		(1	)		(6	)		—			(7	)		(7	)
Other, net		17			2			10			19			13
Total unusual, infrequent and other items		47			89			(82	)		136			(189	)
Income tax (benefit) provision of adjustments at effective tax rate		(13	)		(25	)		23			(38	)		53
Income tax (benefit) provision - out of period		—			—			—			—			(31	)
Adjusted net income	$	42		$	54		$	38		$	96		$	231
Net income (loss) per share - basic	$	0.12		$	(0.14	)	$	1.39		$	(0.03	)	$	5.65
Net income (loss) per share - diluted	$	0.11		$	(0.14	)	$	1.35		$	(0.03	)	$	5.47
Adjusted net income per share - basic	$	0.62		$	0.78		$	0.55		$	1.40		$	3.28
Adjusted net income per share - diluted	$	0.60		$	0.75		$	0.53		$	1.35		$	3.18

ADJUSTED EBITDAX
CRC defines Adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. CRC believes this measure provides useful information in assessing its financial condition, results of operations and cash flows and is widely used by the industry, the investment community and its lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing CRC’s financial performance, such as its cost of capital and tax structure, as well as depreciation, depletion and amortization of CRC's assets. This measure should be read in conjunction with the information contained in CRC’s financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX is a material component of certain of its financial covenants under CRC's Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP.   The following table represents a reconciliation of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX. CRC has supplemented its non-GAAP measures of consolidated adjusted EBITDAX with adjusted EBITDAX for its exploration and production and corporate items (Adjusted EBITDAX for E&P, Corporate & Other) which management believes is a useful measure for investors to understand the results of the core oil and gas business. CRC defines adjusted EBITDAX for E&P, Corporate & Other as consolidated adjusted EBITDAX less results attributable to its carbon management business (CMB).
	2nd Quarter			1st Quarter			2nd Quarter			YTD June			YTD June
($ millions, except per BOE amounts)		2024			2024			2023			2024			2023
Net income (loss)	$	8		$	(10	)	$	97		$	(2	)	$	398
Interest and debt expense		17			13			14			30			28
Depreciation, depletion and amortization		53			53			56			106			114
Income tax provision (benefit)		3			(9	)		38			(6	)		113
Exploration expense		—			1			1			1			2
Interest income		(8	)		(6	)		(5	)		(14	)		(9	)
Unusual, infrequent and other items ^(1)		47			89			(82	)		136			(189	)
Non-cash items
Accretion expense		13			12			11			25			23
Stock-based compensation		6			5			8			11			15
Post-retirement medical and pension		—			1			—			1			1
Adjusted EBITDAX	$	139		$	149		$	138		$	288		$	496
Net cash provided by operating activities	$	97		$	87		$	108		$	184		$	418
Cash interest payments		1			21			2			22			25
Cash interest received		(8	)		(6	)		(5	)		(14	)		(9	)
Cash income taxes		4			22			51			26			51
Exploration expenditures		—			1			1			1			2
Adjustments to working capital changes		45			24			(19	)		69			9
Adjusted EBITDAX	$	139		$	149		$	138		$	288		$	496
E&P, Corporate & Other Adjusted EBITDAX	$	160		$	162		$	151		$	322		$	518
CMB Adjusted EBITDAX	$	(21	)	$	(13	)	$	(13	)	$	(34	)	$	(22	)
Adjusted EBITDAX per Boe	$	20.23		$	21.47		$	17.59		$	20.86		$	31.23
^(1) See Adjusted Net Income (Loss) reconciliation.

FREE CASH FLOW AND SUPPLEMENTAL CASH FLOW MEASURES
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. CRC supplemented its non-GAAP measure of free cash flow with (i) net cash provided by operating activities before changes in operating assets and liabilities, net, (ii) adjusted free cash flow, and (iii) adjusted free cash flow of exploration and production, and corporate and other items (Free Cash Flow for E&P, Corporate & Other), which it believes is a useful measure for investors to understand the results of CRC's core oil and gas business. CRC defines Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to its carbon management business (CMB). CRC defines adjusted free cash flow as free cash flow before transaction and integration costs from the Aera Merger.
	2nd Quarter			1st Quarter			2nd Quarter			YTD June			YTD June
($ millions)		2024			2024			2023			2024			2023
Net cash provided by operating activities before working capital changes	$	108		$	92		$	98		$	200		$	414
Working capital changes		(11	)		(5	)		10			(16	)		4
Net cash provided by operating activities		97			87			108			184			418
Capital investments		(34	)		(54	)		(39	)		(88	)		(86	)
Free cash flow	$	63		$	33		$	69		$	96		$	332
Add: Aera transaction and integration costs		13			13			—			26			—
	$	76		$	46		$	69		$	122		$	332
E&P, Corporate and Other ^(1)	$	95		$	53		$	78		$	148		$	348
CMB ^(1)	$	(19	)	$	(7	)	$	(9	)	$	(26	)	$	(16	)
Adjustments to capital investments:
Replacement water facilities^(2)	$	—		$	—		$	1		$	—		$	2
Adjusted capital investments:
E&P, Corporate and Other	$	36		$	50		$	38		$	86		$	83
CMB	$	(2	)	$	4		$	1		$	2		$	3
Adjusted free cash flow:
E&P, Corporate and Other	$	95		$	53		$	79		$	148		$	350
CMB	$	(19	)	$	(7	)	$	(10	)	$	(26	)	$	(18	)
^(1) CMB free cash flow previously reported for the first three months of 2024 was $(17) million and was corrected to $(7) million to account for noncash add backs related to leases. We define free cash flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to the carbon management business. Accordingly, this change impacted our previously reported E&P, Corporate & Other free cash flow from $63 million to $53 million for the first three months of 2024
^(2) Facilities capital includes $0, $1 million and $1 million in the first quarter of 2024 and fourth and first quarter of 2023, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this press release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital.

ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES
Management uses a measure called adjusted general and administrative (G&A) expenses to provide useful information to investors interested in comparing CRC's costs between periods and performance to our peers. CRC supplemented its non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of its exploration and production and corporate items (adjusted general & administrative expenses for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results or CRC's core oil and gas business. CRC defines adjusted general & administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to its carbon management business (CMB).
	2nd Quarter			1st Quarter			2nd Quarter			YTD June			YTD June
($ millions)		2024			2024			2023			2024			2023
General and administrative expenses	$	63		$	57		$	71		$	120		$	136
Stock-based compensation		(6	)		(5	)		(8	)		(11	)		(15	)
Information technology infrastructure		(1	)		(2	)		(6	)		(3	)		(9	)
Other		—			(1	)		—			(1	)		—
Adjusted G&A expenses	$	56		$	49		$	57		$	105		$	112
E&P, Corporate and Other adjusted G&A expenses	$	53		$	47		$	54		$	100		$	106
CMB adjusted G&A expenses	$	3		$	2		$	3		$	5		$	6
OPERATING COSTS PER BOE
The reporting of PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only CRC's net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSCs.
	2nd Quarter			1st Quarter			2nd Quarter			YTD June			YTD June
($ per BOE)		2024			2024			2023			2024			2023
Energy operating costs ^(1)	$	6.40		$	8.07		$	7.39		$	7.24		$	11.52
Gas processing costs ^(2)		0.44			0.58			0.64			0.51			0.63
Non-energy operating costs		16.30			17.15			15.68			16.73			15.56
Operating costs	$	23.14		$	25.80		$	23.71		$	24.48		$	27.71
Costs attributable to PSCs
Excess energy operating costs attributable to PSCs	$	(0.94	)	$	(0.99	)	$	(0.91	)	$	(0.97	)	$	(0.98	)
Excess non-energy operating costs attributable to PSCs		(1.62	)		(1.55	)		(1.24	)		(1.58	)		(1.21	)
Excess costs attributable to PSCs	$	(2.56	)	$	(2.54	)	$	(2.15	)	$	(2.55	)	$	(2.19	)
Energy operating costs, excluding effect of PSCs ^(1)	$	5.46		$	7.08		$	6.48		$	6.27		$	10.54
Gas processing costs, excluding effect of PSCs ^(2)		0.44			0.58			0.64			0.51			0.63
Non-energy operating costs, excluding effect of PSCs		14.68			15.60			14.44			15.15			14.35
Operating costs, excluding effects of PSCs	$	20.58		$	23.26		$	21.56		$	21.93		$	25.52
^(1) Energy operating costs consist of purchased natural gas used to generate electricity for operations and steamfloods, purchased electricity and internal costs to generate electricity used in CRC's operations.
^(2)Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills.

Attachment 4
PRODUCTION STATISTICS
	2nd Quarter	1st Quarter	2nd Quarter	YTD June	YTD June
Net Production Per Day	2024	2024	2023	2024	2023
Oil (MBbl/d)
San Joaquin Basin	30	30	34	30	35
Los Angeles Basin	17	18	19	17	19
Total	47	48	53	47	54
NGLs (MBbl/d)
San Joaquin Basin	10	11	11	11	11
Total	10	11	11	11	11
Natural Gas (MMcf/d)
San Joaquin Basin	99	90	119	94	119
Los Angeles Basin	1	1	1	1	1
Sacramento Basin	14	14	15	14	16
Total	114	105	135	109	136
Total Production (MBoe/d)	76	76	86	76	88
Gross Operated and Net Non-Operated	2nd Quarter	1st Quarter	2nd Quarter	YTD June	YTD June
Production Per Day	2024	2024	2023	2024	2023
Oil (MBbl/d)
San Joaquin Basin	33	34	38	33	39
Los Angeles Basin	24	24	25	24	25
Total	57	58	63	57	64
NGLs (MBbl/d)
San Joaquin Basin	11	11	12	11	12
Total	11	11	12	11	12
Natural Gas (MMcf/d)
San Joaquin Basin	125	128	136	127	135
Los Angeles Basin	7	7	7	7	7
Sacramento Basin	17	17	19	17	20
Total	149	152	162	151	162
Total Production (MBoe/d)	93	94	103	93	103

Attachment 5
PRICE STATISTICS
	2nd Quarter			1st Quarter			2nd Quarter			YTD June			YTD June
		2024			2024			2023			2024			2023
Oil ($ per Bbl)
Realized price with derivative settlements	$	81.29		$	77.17		$	63.66		$	79.20		$	63.35
Realized price without derivative settlements	$	83.14		$	80.16		$	75.77		$	81.63		$	77.25
NGLs ($/Bbl)	$	46.96		$	50.50		$	42.48		$	48.76		$	50.88
Natural gas ($/Mcf)
Realized price with derivative settlements	$	1.78		$	3.90		$	3.46		$	2.81		$	12.44
Realized price without derivative settlements	$	1.78		$	3.90		$	3.46		$	2.81		$	12.44
Index Prices
Brent oil ($/Bbl)	$	85.00		$	81.84		$	78.01		$	83.42		$	80.12
WTI oil ($/Bbl)	$	80.57		$	76.96		$	73.78		$	78.77		$	74.95
NYMEX average monthly settled price ($/MMBtu)	$	1.89		$	2.24		$	2.10		$	2.07		$	2.76
Realized Prices as Percentage of Index Prices
Oil with derivative settlements as a percentage of Brent		96	%		94	%		82	%		95	%		79	%
Oil without derivative settlements as a percentage of Brent		98	%		98	%		97	%		98	%		96	%
Oil with derivative settlements as a percentage of WTI		101	%		100	%		86	%		101	%		85	%
Oil without derivative settlements as a percentage of WTI		103	%		104	%		103	%		104	%		103	%
NGLs as a percentage of Brent		55	%		62	%		54	%		58	%		64	%
NGLs as a percentage of WTI		58	%		66	%		58	%		62	%		68	%
Natural gas with derivative settlements as a percentage of NYMEX contract month average		94	%		174	%		165	%		136	%		451	%
Natural gas without derivative settlements as a percentage of NYMEX contract month average		94	%		174	%		165	%		136	%		451	%

Attachment 6
SECOND QUARTER 2024 DRILLING ACTIVITY
	San Joaquin	Los Angeles	Ventura	Sacramento
Wells Drilled	Basin	Basin	Basin	Basin	Total
Development Wells
Primary	3	—	—	—	3
Waterflood	—	—	—	—	—
Steamflood	—	—	—	—	—
Total^(1)	3	—	—	—	3
SIX MONTHS 2024 DRILLING ACTIVITY
	San Joaquin	Los Angeles	Ventura	Sacramento
Wells Drilled	Basin	Basin	Basin	Basin	Total
Development Wells
Primary	5	—	—	—	5
Waterflood	—	—	—	—	—
Steamflood	—	—	—	—	—
Total^(1)	5	—	—	—	5
^(1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled.

				Attachment 7
OIL HEDGES AS OF JUNE 30, 2024
	Q3 2024	Q4 2024	Q1 2025	Q2 2025	2H 2025
Sold Calls
Barrels per day	30,000	29,000	30,000	30,000	29,500
Weighted-average Brent price per barrel	$90.07	$90.07	$87.08	$87.08	$87.11
Swaps
Barrels per day	8,875	8,875	5,250	3,500	3,250
Weighted-average Brent price per barrel	$80.10	$79.94	$76.27	$72.50	$72.50
Purchased Puts
Barrels per day	30,000	29,000	30,000	30,000	29,500
Weighted-average Brent price per barrel	$65.17	$65.17	$61.67	$61.67	$61.69