California Resources Reports Third Quarter 2024 Financial and Operating Results

LONG BEACH, Calif., Nov. 05, 2024 (GLOBE NEWSWIRE) -- California Resources Corporation (NYSE: CRC) today reported financial and operating results for the third quarter of 2024. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Wednesday, November 6, 2024. Participation details can be found within this release. In addition, supplemental slides are available on CRC’s website at www.crc.com.

Highlights

• Generated $345 million of net income, $137 million of adjusted net income¹ and $402 million of adjusted EBITDAX¹
• Generated $220 million of net cash provided by operating activities, $249 million of net cash provided by operating activities before changes in operating assets and liabilities¹ and $141 million of free cash flow¹
• Strong third quarter 2024 average net production sold of 145 thousand barrels of oil equivalent per day (MBoe/d) and average net oil production sold of 113 thousand barrels of oil per day (MBo/d). Drilling and workover capital investments were $38 million
• On-track to deliver approximately $235 million in targeted Aera merger-related synergies by the third quarter of 2025 with $135 million of synergies actioned to date including a reduction of $60 million² in annual interest expense
• Returned 54% of quarterly free cash flow¹, or $76 million, to shareholders including $42 million in share repurchases and $34 million in dividends
• Optimized capital structure and extended maturities through recent $300 million follow-on offering of 8.250% senior notes due 2029 (2029 Senior Notes) and subsequent tender of $300 million 7.125% senior notes due 2026 (2026 Senior Notes)
• Exited the quarter with $213 million in cash and cash equivalents and $1,138 million of liquidity³
• Received California's first conditional use permits for Carbon TerraVault I CCS project in Kern County and signed a memorandum of understanding⁴ (MOU) to develop carbon capture and storage (CCS) solutions with Hull Street Energy LLC, a leading California power partner. See Carbon TerraVault's Third Quarter 2024 Update for additional information

"Our performance this year has been strong and we have positioned CRC for long term value creation into the future," said Francisco Leon, CRC's President and Chief Executive Officer. "Today, CRC is bigger, stronger, and more sustainable. We continue to demonstrate that we are a different kind of energy company. I am really proud of our teams and the Aera integration. We are capturing meaningful synergies, enhancing operating efficiencies and advancing new growth opportunities. The Kern County Board of Supervisors’ approval of the conditional use permits for our CTV I project and a recent MOU with a leading power partner are a testament to our team's relentless pursuit of growing our carbon business. As we look to 2025, our hedge positions underpin near-term cash flows and will allow for continued debt reduction and cash returns to shareholders."

Third Quarter 2024 Financial and Operating Summary

CRC reported net income of $345 million, or $3.78 per fully diluted share of common stock, and adjusted net income¹ of $137 million, or $1.50 per fully diluted share. Net cash provided by operating activities was $220 million.

Transaction and integration costs related to the Aera merger decreased third quarter 2024 cash flow from operations by $57 million. Employee severance and related costs during the three months ended September 30, 2024 were $27 million. CRC expects to pay severance costs of approximately $25 million in the fourth quarter of 2024 and the remaining amounts throughout 2025 as the workforce reduction will be achieved in stages due to transition periods.

Gross production averaged 165 MBoe/d and net production sold averaged 145 MBoe/d, including net oil production sold of 113 MBo/d. Net oil production was positively impacted by approximately 1 MBo/d, as compared to the second quarter of 2024, a result CRC's production-sharing contracts (PSCs). Average realized oil prices were 98% of Brent.

Operating costs of $311 million reflected reduced activity levels, lower natural gas prices and the early realization of Aera merger-related synergies.

Capital investments of $79 million were lower than guidance primarily due to high-grading of workover capital.

Selected Production, Price Information and Results of Operations			3rd Quarter					2nd Quarter
($ in millions)			2024					2024
Net oil production sold per day (MBbl/d)				113					47
Realized oil price with derivative settlements ($ per Bbl)			$	75.38				$	81.29
Net NGL production sold per day (MBbl/d)				11					10
Realized NGL price ($ per Bbl)			$	45.77				$	46.96
Net natural gas production sold per day (Mmcf/d)				126					114
Realized natural gas price with derivative settlements ($ per Mcf)			$	2.68				$	1.78
Net total production sold per day (MBoe/d)				145					76
Margin from marketing of purchased commodities5 ($ millions)			$	8				$	8
Margin from electricity sales6 ($ millions)			$	60				$	22
Net gain from commodity derivatives ($ millions)			$	356				$	5
Selected Financial Statement Data and non-GAAP measures:			3rd Quarter					2nd Quarter
($ and shares in millions, except per share amounts)			2024					2024
Statements of Operations:
Revenues
Total operating revenues			$	1,353				$	514
Selected Expenses
Operating costs			$	311				$	156
General and administrative expenses			$	106				$	63
Adjusted general and administrative expenses1			$	89				$	56
Taxes other than on income			$	85				$	39
Transportation costs			$	23				$	17
Operating Income (loss)			$	518				$	38
Interest and debt expense			$	(29)				$	(17)
Income tax benefit (provision)			$	(138)				$	(3)
Net (loss) Income			$	345				$	8
EPS, Non-GAAP Measures and Select Balance Sheet Data
Adjusted net income1			$	137				$	42
Weighted-average common shares outstanding - diluted				91.2					70.0
Net loss (income) per share - diluted			$	3.78				$	0.11
Adjusted net income1 per share - diluted			$	1.50				$	0.60
Adjusted EBITDAX1			$	402				$	139
Net cash provided by operating activities			$	220				$	97
Net cash provided by operating activities before changes in operating assets and liabilities, net1			$	249				$	108
Capital investments			$	79				$	34
Free cash flow1			$	141				$	63
Cash and cash equivalents			$	241				$	1,031

Guidance

The following table provides guidance for key fourth quarter financial and operating metrics. For the balance of 2024, CRC expects to run a one-rig program.

CRC has actioned $135 million in Aera merger related synergies during the second half of 2024 and remains on-track to deliver approximately $235 million in estimated synergies by the third quarter of 2025. A reduction of $60 million² in annual interest expense was achieved in the second quarter of 2024 and third quarter results reflect approximately $8 million of run rate savings. Looking forward, fourth quarter guidance includes $22 million of actioned synergies and the next $45 million of actioned Aera merger synergies are expected to be gradually reflected throughout 2025.

CRC plans to implement the final $100 million of projected operational and general and administrative Aera merger related synergies next year, with the benefits expected to be realized throughout 2025 and 2026. Projected operational synergies are expected to reduce operating costs, ARO, and capital. CRC plans to provide additional details of these operations synergies with its full year 2025 guidance during its fourth quarter 2024 earnings call. See Attachment 2 for additional information.

CRC Guidance7	Total 4Q24E
Net Production Sold (MBoe/d)	140 - 144
Oil Production Sold (%)	~79%
Capital ($ millions)	$85 - $105
Adjusted EBITDAX1 ($ millions)	$260 - $300

Shareholder Returns

CRC is committed to returning cash to shareholders through dividends and repurchases of common stock. During the third quarter of 2024, CRC repurchased 0.835 million shares for $42 million at an average price of $50.23 per share.

On November 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 December 2, 2024 and will be paid on December 16, 2024.

Since May 2021, CRC has returned approximately $1,022 million of cash to its stakeholders, including $736 million⁸ in share repurchases, $231 million in dividends and redemption of $55 million in principal of its 2026 Senior Notes which reduced overall leverage.

In October 2020, CRC reserved an aggregate 4.384 million shares of its common stock for warrants, which were exercisable at $36 per share through October 28, 2024.

Since the issuance date of the warrants in October 2020, 3.857 million shares have been issued upon the exercise of warrants and, 0.469 million shares were cancelled due to net settlement. On October 28, 2024, any unexercised warrants expired in accordance with their terms and 57,920 shares underlying such warrants were never issued.

Balance Sheet and Liquidity

On August 22, 2024, CRC completed a follow-on offering of $300 million in aggregate principal amount of 2029 Senior Notes. The net proceeds of $298 million from the issuance, which included $3 million of premium and $5 million of issuance costs, were used to repurchase $300 million of CRC's 2026 Senior Notes in a tender offer.

As of September 30, 2024, CRC had liquidity of $1,138 million³, which consisted of $213 million in available cash and cash equivalents³ plus $925 million of availability under the Revolving Credit Facility which reflects $1,100 million of borrowing capacity, less $175 million of outstanding letters of credit.

On November 1, 2024, CRC reaffirmed its $1.5 billion borrowing base and amended its existing Revolving Credit Facility. The amendments included extending the maturity date of the facility to March 16, 2029, amending the springing maturity to permit its 2026 Senior Notes to remain outstanding past October 31, 2025 under certain circumstances, increasing the amount of elected commitments by $50 million, and other technical amendments.

Upcoming Investor Conference Participation

CRC plans to participate in the following events in November and December 2024:

• Bank of America Global Energy Conference 2024 on November 12 to 13 in Houston, TX
• TD Securities Energy Conference on November 19 to 20 in New York, NY
• Wolfe Research Inaugural Oil & Gas Conference on November 21, Virtual
• 2024 Stephens Annual Investment Conference on November 22 in Nashville, TN
• Mizuho Power, Energy & Infrastructure Conference 2024 on December 9 in New York, NY
• 23rd Annual Wells Fargo Midstream, Energy & Utilities Symposium on December 10 in New York, NY
• Capital One Securities Energy Conference on December 10 in Houston, TX
  

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

Conference Call Details

A conference call is scheduled for 1 p.m. ET (10 a.m. PT) on Wednesday, November 6, 2024. To participate in the call, dial (877) 328-5505 (International calls please 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/10192326/fd6685ad6e. 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.

¹ See 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 4Q24 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 3.
² As of June 30, 2024. When accounting for estimated cash interest income, CRC’s net interest savings were ~$36 million.
³ Excludes restricted cash of $28 million.
⁴ The MOU is non-binding and subject to negotiation of definitive agreements.
⁵ 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
⁶ Electricity Margin is calculated as the difference between Electricity Sales and Electricity Generation Expenses
⁷ 4Q24 guidance assumes Brent price of $71.48 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. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.
⁸ The total value of shares purchased excludes approximately $3 million related to excise taxes and commissions paid on share repurchases.

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, Lebanon, Ukraine, Yemen and the Red Sea;
• the ability to successfully execute integration efforts in connection with CRC's merger with Aera Energy LLC, and achieve projected synergies and ensure that such synergies are sustainable;
• 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, EPA and other governmental 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 efforts of activists to delay or prevent oil and gas activities or the development of CRC's carbon management business through a variety of tactics, including litigation;
• 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 and MOUs 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.

Contacts:

Joanna Park (Investor Relations) 818-661-3731 Joanna.Park@crc.com

Richard Venn (Media) 818-661-6014 Richard.Venn@crc.com

Attachment 1
SUMMARY OF RESULTS
	3rd Quarter				2nd Quarter				3rd Quarter					Nine Months				Nine Months
($ and shares in millions, except per share amounts)	2024				2024				2023					2024				2023
Statements of Operations:
Revenues
Oil, natural gas and NGL sales	$	870			$	412			$	510				$	1,711			$	1,672
Net gain (loss) from commodity derivatives		356				5				(204)					290				(131)
Revenue from marketing of purchased commodities		51				51				77					176				336
Electricity sales		69				36				67					120				169
Other revenue		7				10				10					24				29
Total operating revenues		1,353				514				460					2,321				2,075
Operating Expenses
Operating costs		311				156				196					643				636
General and administrative expenses		106				63				65					226				201
Depreciation, depletion and amortization		140				53				56					246				170
Asset impairment		—				13				—					13				3
Taxes other than on income		85				39				48					162				132
Exploration expense		1				—				—					2				2
Costs related to marketing of purchased commodities		43				43				31					140				182
Electricity generation expenses		9				14				23					31				85
Transportation costs		23				17				16					60				49
Accretion expense		31				13				12					56				35
Carbon management business expenses		13				15				7					36				20
Other operating expenses, net		73				51				21					161				42
Total operating expenses		835				477				475					1,776				1,557
Net gain on asset divestitures		—				1				—					7				7
Operating Income (Loss)		518				38				(15)					552				525
Non-Operating (Expenses) Income
Interest and debt expense		(29)				(17)				(15)					(59)				(43)
Loss from investment in unconsolidated subsidiary		(2)				(4)				(3)					(9)				(6)
Net loss on early extinguishment of debt		(5)				—				—					(5)				—
Other non-operating income (loss), net		1				(6)				3					(4)				5
Income Before Income Taxes		483				11				(30)					475				481
Income tax (provision) benefit		(138)				(3)				8					(132)				(105)
Net Income	$	345			$	8			$	(22)				$	343			$	376
Net income (loss) per share - basic	$	3.86			$	0.12			$	(0.32)				$	4.54			$	5.38
Net income (loss) per share - diluted	$	3.78			$	0.11			$	(0.32)				$	4.42			$	5.18
Adjusted net income	$	137			$	42			$	74				$	233			$	305
Adjusted net income per share - basic	$	1.53			$	0.62			$	1.08				$	3.09			$	4.36
Adjusted net income per share - diluted	$	1.50			$	0.60			$	1.02				$	3.00			$	4.20
Weighted-average common shares outstanding - basic		89.4				68.1				68.7					75.5				69.9
Weighted-average common shares outstanding - diluted		91.2				70.0				68.7					77.6				72.6
Adjusted EBITDAX	$	402			$	139			$	187				$	690			$	683
Effective tax rate		29%				27%				27%					28%				22%
	3rd Quarter				2nd Quarter				3rd Quarter					Nine Months				Nine Months
($ in millions)	2024				2024				2023					2024				2023
Cash Flow Data:
Net cash provided by operating activities	$	220			$	97			$	104				$	404			$	522
Net cash used in investing activities	$	(928)			$	(33)			$	(28)				$	(1,010)			$	(133)
Net cash (used) provided by financing activities	$	(82)			$	564			$	(45)				$	351			$	(217)
	September 30,				December 31,
($ in millions)	2024				2023
Selected Balance Sheet Data:
Total current assets	$	872			$	929
Property, plant and equipment, net	$	5,836			$	2,770
Deferred tax asset	$	50			$	132
Total current liabilities	$	897			$	616
Long-term debt, net	$	1,131			$	540
Noncurrent asset retirement obligations	$	1,083			$	422
Deferred tax liability	$	124			$	—
Total stockholders' equity	$	3,501			$	2,219

GAINS AND LOSSES FROM COMMODITY DERIVATIVES
	3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions)	2024				2024				2023				2024				2023
Non-cash derivative gain (loss)	$	373			$	11			$	(109)			$	325			$	92
Net payments on settled commodity derivatives		(17)				(6)				(95)				(35)				(223)
Net gain (loss) from commodity derivatives	$	356			$	5			$	(204)			$	290			$	(131)

CAPITAL INVESTMENTS
	3rd Quarter			2nd Quarter				3rd Quarter			Nine Months			Nine Months
($ millions)	2024			2024				2023			2024			2023
Facilities (1)	$	36		$	17			$	7		$	67		$	27
Drilling		19			18				13			52			51
Workovers		19			11				11			37			28
Total E&P capital		74			46				31			156			106
CMB (1)		4			(2)				—			6			1
Corporate and other		1			(10)				2			5			12
Total capital program	$	79		$	34			$	33		$	167		$	119
(1) Facilities capital includes $1 million in the third quarter of 2023, and $3 million for the nine months 2023, 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 4Q24E			CMB 4Q24E		E&P, Corp. & Other 4Q24E
Net Production Sold (MBoe/d)	140 - 144					140 - 144
Oil Production Sold (%)	~79%					~79%
CMB Expenses & Operating Costs ($ millions)	$340 - $365			$15 - $25		$325 - $340
General and Administrative Expenses ($ millions)	$90 - $100			$2 - $4		$88 - $96
Adjusted General and Administrative Expenses ($ millions)	$80 - $90			$1 - $3		$79 - $87
Capital ($ millions)	$85 - $105			$5 - $10		$80 - $95
Drilling & completions, workover ($ millions)	$37 - $45
Facilities ($ millions)	$40 - $45
Carbon management business ($ millions)	$5 - $10
Corporate & other ($ millions)	$3 - $5
Adjusted EBITDAX ($ millions)	$260 - $300
Margin from Marketing of Purchased Commodities ($ millions) (1)	$5 - $10					$5 - $10
Electricity Margin ($ millions) (2)	$15 - $20					$15 - $20
Other Operating Revenue & Expenses, net ($ millions)(3)	($10) - ($20)					($10) - ($20)
Transportation Costs ($ millions)	$20 - $25					$20 - $25
Taxes Other Than on Income ($ millions)	$75 - $86					$75 - $86
Interest and Debt Expense ($ millions)	$25 - $30					$25 - $30
Commodity Assumptions:
Brent ($/Bbl)	$71.48					$71.48
NYMEX ($/Mcf)	$2.95					$2.95
Oil - % of Brent:	95% to 99%					95% to 99%
NGL - % of Brent:	65% to 69%					65% to 69%
Natural Gas - % of NYMEX:	128% to 138%					128% to 138%

⁽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.
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

	4Q24 Estimated
	Consolidated								CMB								E&P, Corporate & Other
($ millions)	Low				High				Low				High				Low				High
General and administrative expenses	$	90			$	100			$	2			$	4			$	88			$	96
Equity-settled stock-based compensation		(9)				(9)				(1)				(1)				(8)				(8)
Other		(1)				(1)												(1)				(1)
Estimated adjusted general and administrative expenses	$	80			$	90			$	1			$	3			$	79			$	87

ESTIMATED ADJUSTED EBITDAX RECONCILIATION

									4Q24E
($ millions)									Low			High
Net income									$	22		$	32
Interest and debt expense, net										25			30
Depreciation, depletion and amortization										135			141
Income taxes										8			14
Unusual, infrequent and other items										15			24
Other non-cash items
Accretion expense										30			32
Stock-settled compensation										5			7
Post-retirement medical and pension										0			0
Estimated adjusted EBITDAX									$	240		$	280
Net cash provided by operating activities									$	158		$	178
Cash interest										37			43
Cash income taxes										45			51
Working capital changes										0			8
Estimated adjusted EBITDAX									$	240		$	280

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.
	3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions, except per share amounts)	2024				2024				2023				2024				2023
Net income (loss)	$	345			$	8			$	(22)			$	343			$	376
Unusual, infrequent and other items:
Non-cash derivative (gain) loss		(373)				(11)				109				(325)				(92)
Asset impairment		—				13				—				13				3
Severance and termination costs		27				1				7				28				10
Aera merger transaction / integration fees		30				13				—				56				—
Increased power and fuel costs due to power plant shutdown		8				15				—				44				—
Net gain (loss) on asset divestitures		—				(1)				—				(7)				(7)
Loss on early extinguishment of debt		5				—				—				5				—
Other, net		6				17				17				25				30
Total unusual, infrequent and other items		(297)				47				133				(161)				(56)
Income tax provision (benefit) of adjustments at effective tax rate		89				(13)				(37)				51				16
Income tax benefit - out of period		—				—				—				—				(31)
Adjusted net income	$	137			$	42			$	74			$	233			$	305
Net income (loss) per share - basic	$	3.86			$	0.12			$	(0.32)			$	4.54			$	5.38
Net income (loss) per share - diluted	$	3.78			$	0.11			$	(0.32)			$	4.42			$	5.18
Adjusted net income per share - basic	$	1.53			$	0.62			$	1.08			$	3.09			$	4.36
Adjusted net income per share - diluted	$	1.50			$	0.60			$	1.02			$	3.00			$	4.20

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).
	3rd Quarter				2nd Quarter					3rd Quarter				Nine Months				Nine Months
($ millions, except per BOE amounts)	2024				2024					2023				2024				2023
Net income (loss)	$	345			$	8				$	(22)			$	343			$	376
Interest and debt expense		29				17					15				59				43
Depreciation, depletion and amortization		140				53					56				246				170
Income tax provision (benefit)		138				3					(8)				132				105
Exploration expense		1				—					—				2				2
Interest income		(1)				(8)					(5)				(15)				(14)
Unusual, infrequent and other items (1)		(297)				47					133				(161)				(56)
Non-cash items
Accretion expense		31				13					12				56				35
Stock-based compensation		6				6					6				17				21
Taxes related to acquisition accounting		10				—					—				10				—
Post-retirement medical and pension		—				—					—				1				1
Adjusted EBITDAX	$	402			$	139				$	187			$	690			$	683
Net cash provided by operating activities	$	220			$	97				$	104			$	404			$	522
Cash interest payments		24				1					23				46				48
Cash interest received		(1)				(8)					(5)				(15)				(14)
Cash income taxes		29				4					29				55				80
Exploration expenditures		1				—					—				2				2
Adjustments to working capital changes		129				45					36				198				45
Adjusted EBITDAX	$	402			$	139				$	187			$	690			$	683
E&P, Corporate & Other Adjusted EBITDAX	$	417			$	160				$	199			$	739			$	717
CMB Adjusted EBITDAX	$	(15)			$	(21)				$	(12)			$	(49)			$	(34)
Adjusted EBITDAX per Boe	$	30.19			$	20.23				$	23.81			$	25.44			$	28.78
(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.
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions)		2024				2024				2023				2024				2023
Net cash provided by operating activities before working capital changes		$	249			$	108			$	129			$	449			$	543
Working capital changes			(29)				(11)				(25)				(45)				(21)
Net cash provided by operating activities			220				97				104				404				522
Capital investments			(79)				(34)				(33)				(167)				(119)
Free cash flow		$	141			$	63			$	71			$	237			$	403
Add: Aera transaction and integration costs			30				13				—				56				—
Free cash flow after special items		$	171			$	76			$	71			$	293			$	403
E&P, Corporate and Other (1)		$	186			$	95			$	79			$	334			$	427
CMB (1)		$	(15)			$	(19)			$	(8)			$	(41)			$	(24)
Adjustments to capital investments:
Replacement water facilities(2)		$	—			$	—			$	1			$	—			$	3
Adjusted capital investments:
E&P, Corporate and Other		$	75			$	36			$	32			$	161			$	115
CMB		$	4			$	(2)			$	1			$	6			$	4
Adjusted free cash flow:
E&P, Corporate and Other		$	186			$	95			$	80			$	334			$	430
CMB		$	(15)			$	(19)			$	(9)			$	(41)			$	(27	)
(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. CRC defines 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 $1 million in the third quarter of 2023 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).
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ millions)		2024				2024				2023				2024				2023
General and administrative expenses		$	106			$	63			$	65			$	226			$	201
Stock-based compensation			(6)				(6)				(6)				(17)				(21)
Information technology infrastructure			—				(1)				(6)				(3)				(13)
Accelerated vesting			(9)				—				—				(9)				—
Retention awards			(2)				—				—				(2)				—
Other			—				—				(2)				(1)				(4)
Adjusted G&A expenses		$	89			$	56			$	51			$	194			$	163
E&P, Corporate and Other adjusted G&A expenses		$	87			$	53			$	47			$	187			$	153
CMB adjusted G&A expenses		$	2			$	3			$	4			$	7			$	10
Adjusted G&A per BOE		$	6.68			$	8.15			$	6.49			$	7.15			$	6.87
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.
		3rd Quarter				2nd Quarter				3rd Quarter				Nine Months				Nine Months
($ per BOE)		2024				2024				2023				2024				2023
Energy operating costs (1)		$	7.29			$	6.40			$	9.42			$	7.26			$	10.87
Gas processing costs (2)			0.38				0.44				0.64				0.44				0.59
Non-energy operating costs			16.06				16.30				14.90				16.41				15.34
Operating costs		$	23.73			$	23.14			$	24.96			$	24.11			$	26.80
Costs attributable to PSCs
Excess energy operating costs attributable to PSCs		$	(0.75)			$	(0.94)			$	(1.09)			$	(0.70)			$	(1.01)
Excess non-energy operating costs attributable to PSCs			(0.48)				(1.62)				(1.30)				(1.18)				(1.25)
Excess costs attributable to PSCs		$	(1.23)			$	(2.56)			$	(2.39)			$	(1.88)			$	(2.26)
Energy operating costs, excluding effect of PSCs (1)		$	6.54			$	5.46			$	8.33			$	6.56			$	9.86
Gas processing costs, excluding effect of PSCs (2)			0.38				0.44				0.64				0.44				0.59
Non-energy operating costs, excluding effect of PSCs			15.58				14.68				13.60				15.23				14.09
Operating costs, excluding effects of PSCs		$	22.50			$	20.58			$	22.57			$	22.23			$	24.54
(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
The tables below present production information on the basis of gross production, net production and production sold. The difference between gross production and net production primarily reflects the reduction for volumes attributable to working interest and royalty owners and volumes associated with PSC-type contracts to arrive at CRC's net share. The difference between net production and net production sold reflects (i) the reduction for natural gas that CRC produces that is used in its oil and gas operations, including steam in its steamflood operations, and (ii) marketing activities reflecting the storage of volumes that CRC produces and are sold at a later time.
Volumes Sold		3rd Quarter		2nd Quarter		3rd Quarter		Nine Months		Nine Months
Net Production Per Day		2024		2024		2023		2024		2023
Oil (MBbl/d)
San Joaquin Basin		90		30		33		50		34
Los Angeles Basin		17		17		18		17		19
Ventura Basin		6		—		—		2		—
Total		113		47		51		69		53
NGLs (MBbl/d)
San Joaquin Basin		11		10		11		11		11
Total		11		10		11		11		11
Natural Gas (MMcf/d)
San Joaquin Basin		111		99		122		99		120
Los Angeles Basin		1		1		1		1		1
Ventura Basin		1		—		—		—		—
Sacramento Basin		13		14		15		14		15
Total		126		114		138		114		136
Total Production (MBoe/d)		145		76		85		99		87
Volumes Produced		3rd Quarter		2nd Quarter		3rd Quarter		Nine Months		Nine Months
Net Production Per Day		2024		2024		2023		2024		2023
Oil (MBbl/d)
San Joaquin Basin		90		30		33		51		34
Los Angeles Basin		17		16		18		17		19
Ventura Basin		6		—		—		2		—
Total		113		46		51		70		53
NGLs (MBbl/d)
San Joaquin Basin		11		11		12		10		11
Total		11		11		12		10		11
Natural Gas (MMcf/d)
San Joaquin Basin		130		118		128		123		127
Los Angeles Basin		1		1		1		1		1
Ventura Basin		3		—		—		1		—
Sacramento Basin		13		14		15		14		16
Total		147		133		144		139		144
Total Production (MBoe/d)		149		79		87		103		88

Attachment 4
PRODUCTION STATISTICS
Gross Operated and Net Non-Operated		3rd Quarter		2nd Quarter		3rd Quarter		Nine Months		Nine Months
Production Per Day		2024		2024		2023		2024		2023
Oil (MBbl/d)
San Joaquin Basin		96		33		36		54		38
Los Angeles Basin		23		24		25		24		25
Ventura Basin		8		—		—		3		—
Total		127		57		61		81		63
NGLs (MBbl/d)
San Joaquin Basin		11		11		13		11		12
Total		11		11		13		11		12
Natural Gas (MMcf/d)
San Joaquin Basin		137		125		135		130		135
Los Angeles Basin		7		7		8		7		7
Ventura Basin		3		—		—		1		—
Sacramento Basin		16		17		18		17		20
Total		163		149		161		155		162
Total Production (MBoe/d)		165		93		101		118		102

																		Attachment 5
PRICE STATISTICS
	3rd Quarter				2nd Quarter					3rd Quarter				Nine Months				Nine Months
	2024				2024					2023				2024				2023
Oil ($ per Bbl)
Realized price with derivative settlements	$	75.38			$	81.29				$	66.12			$	77.10			$	64.25
Realized price without derivative settlements	$	77.10			$	83.14				$	85.36			$	79.15			$	79.90
NGLs ($/Bbl)	$	45.77			$	46.96				$	44.95			$	47.77			$	48.89
Natural gas ($/Mcf)
Realized price with derivative settlements	$	2.68			$	1.78				$	4.83			$	2.76			$	9.85
Realized price without derivative settlements	$	2.68			$	1.78				$	4.83			$	2.76			$	9.85
Index Prices
Brent oil ($/Bbl)	$	78.54			$	85.00				$	85.95			$	81.79			$	82.06
WTI oil ($/Bbl)	$	75.09			$	80.57				$	82.26			$	77.54			$	77.39
NYMEX average monthly settled price ($/MMBtu)	$	2.16			$	1.89				$	2.55			$	2.10			$	2.69
Realized Prices as Percentage of Index Prices
Oil with derivative settlements as a percentage of Brent		96%				96%					77%				94%				78%
Oil without derivative settlements as a percentage of Brent		98%				98%					99%				97%				97%
Oil with derivative settlements as a percentage of WTI		100%				101%					80%				99%				83%
Oil without derivative settlements as a percentage of WTI		103%				103%					104%				102%				103%
NGLs as a percentage of Brent		58%				55%					52%				58%				60%
NGLs as a percentage of WTI		61%				58%					55%				62%				63%
Natural gas with derivative settlements as a percentage of NYMEX contract month average		124%				94%					189%				131%				366%
Natural gas without derivative settlements as a percentage of NYMEX contract month average		124%				94%					189%				131%				366%

									Attachment 6
THIRD QUARTER 2024 DRILLING ACTIVITY
	San Joaquin		Los Angeles		Ventura		Sacramento
Wells Drilled	Basin		Basin		Basin		Basin		Total
Development Wells
Primary	1		—		—		—		1
Waterflood	—		—		—		—		—
Steamflood	—		—		—		—		—
Total (1)	1		—		—		—		1
NINE MONTHS 2024 DRILLING ACTIVITY
	San Joaquin		Los Angeles		Ventura		Sacramento
Wells Drilled	Basin		Basin		Basin		Basin		Total
Development Wells
Primary	6		—		—		—		6
Waterflood	—		—		—		—		—
Steamflood	—		—		—		—		—
Total (1)	6		—		—		—		6
(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 SEPTEMBER 30, 2024
			Q4 2024			Q1 2025			Q2 2025			Q3 2025			Q4 2025			2026			2027			2028
Sold Calls
Barrels per day				29,000			30,000			30,000			30,000			29,000			5,000			—			—
Weighted-average Brent price per barrel			$90.07			$87.08			$87.08			$87.08			$87.13			$85.00				$—			$—
Swaps
Barrels per day				59,014			52,837			45,631			44,126			42,626			30,449			13,882			10,353
Weighted-average Brent price per barrel			$74.90			$72.48			$71.31			$70.62			$69.94			$67.95			$65.53			$65.00
Purchased Puts
Barrels per day				29,000			30,000			30,000			30,000			29,000			5,000			—			—
Weighted-average Brent price per barrel			$65.17			$61.67			$61.67			$61.67			$61.72			$60.00				$—			$—

																						Attachment 7
NATURAL GAS HEDGES AS OF SEPTEMBER 30, 2024
				Q4 2024			Q1 2025			Q2 2025			Q3 2025			Q4 2025			2026			2027			2028
SoCal Border
MMBtu per day					20,000			10,000			29,074			25,750			22,408			—			—			—
Weighted-average price per MMBtu				$5.49			$6.02			$3.44			$3.48			$3.53				$—			$—			$—
Northwest Pipeline (NWPL) Rockies
MMBtu per day					50,999			50,999			51,750			51,750			51,750			35,336			12,616			9,613
Weighted-average price per MMBtu				$4.67			$5.48			$2.95			$2.95			$4.22			$4.04			$4.34			$3.95
PG&E Citygate
MMBtu per day					14,000			14,000			—			—			—			—			—			—
Weighted-average price per MMBtu				$5.60			$6.10				$—			$—			$—			$—			$—			$—

This press release was published by a CLEAR® Verified individual.