California Resources Corporation Reports Third Quarter 2025 Financial and Operating Results
Raised Quarterly Dividend by 5%
Early Redemption of All Remaining 2026 Senior Notes
LONG BEACH, Calif, Nov. 04, 2025 (GLOBE NEWSWIRE) -- California Resources Corporation (NYSE: CRC) (CRC) today reported financial and operating results for the third quarter of 2025. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Wednesday, November 5, 2025. Conference call details can be found within this release.
Third Quarter Highlights
- Reported net income of $64 million, adjusted net income1 of $123 million and $338 million of adjusted EBITDAX1
- Generated net cash provided by operating activities of $279 million and $188 million of free cash flow1
- Delivered 137 thousand barrels of oil equivalent per day (MBoe/d) (78% oil); total capital of $91 million included drilling, completions and workover capital1 of $43 million
- Increased quarterly dividend by 5%, reinforcing commitment to sustainable shareholder returns; declared quarterly dividend of $0.405/share to be paid in the fourth quarter of 20252
- Ended the third quarter of 2025 with $180 million in available cash and cash equivalents3, $974 million in available borrowing capacity and $1,154 million of liquidity
Other Highlights
- Announced the signing of a definitive agreement and plan of merger to combine with Berry Corporation (bry) (NASDAQ: BRY) (Berry) in an all-stock transaction
- Received an upgrade to CRC's Corporate Family Rating from Moody’s and Fitch revised CRC's outlook from stable to positive
- Redeemed all remaining 2026 Senior Notes for $122 million at par, extending CRC's maturity profile
- Announced a memorandum of understanding4 (MOU) with Capital Power to explore decarbonized power solutions in California. See Carbon TerraVault’s Third Quarter 2025 Update for additional information
- Published the 2024 Sustainability Report providing an overview of CRC’s sustainability efforts and performance
- Received “Grade A” certification through MiQ’s Methane Emissions Performance Standard for CRC's operating assets in Ventura County
“I am very proud of the solid results the CRC team posted this quarter which demonstrate the strength of the CRC business model and our disciplined approach to creating long term shareholder value," said Francisco Leon, CRC’s President and Chief Executive Officer. “Our continued focus on execution, including the pending merger with Berry, coupled with our strong balance sheet, and robust liquidity profile distinguishes us from our peers and positions us to create further value for our shareholders on the road ahead.”
Third Quarter 2025 Comparative Financial Results
| Select Production, Price and Financial Results and Non-GAAP Measures | 3rd Quarter | 2nd Quarter |
|||||||
| ($ in millions except production and prices) |
2025 |
2025 |
|||||||
| Net oil production per day (MBbl/d) | 107 | 109 | |||||||
| Realized oil price without derivative settlements ($ per Bbl) | $ | 66.32 | $ | 65.07 | |||||
| Realized oil price with derivative settlements1($ per Bbl)1 | $ | 67.04 | $ | 66.73 | |||||
| Net NGL production per day (MBbl/d) | 10 | 10 | |||||||
| Realized NGL price ($ per Bbl) | $ | 41.04 | $ | 42.41 | |||||
| Net natural gas production per day (Mmcf/d) | 118 | 111 | |||||||
| Realized natural gas price ($ per Mcf) | $ | 3.47 | $ | 2.79 | |||||
| Net total production per day (MBoe/d) | 137 | 137 | |||||||
| Margin from purchased commodities1 | $ | 14 | $ | 15 | |||||
| Electricity margin1 | $ | 90 | $ | 53 | |||||
| Net (loss) gain from commodity derivatives | $ | (23 | ) | $ | 157 | ||||
| Other operating expenses net of other revenue1 | $ | 25 | $ | 60 | |||||
| Select Financial Statement Data and Non-GAAP Measures: |
3rd Quarter |
2nd Quarter |
|||||||
| ($ and shares in millions, except per share amounts) |
2025 |
2025 |
|||||||
| Total operating revenues | $ | 855 | $ | 978 | |||||
| Operating costs | $ | 316 | $ | 295 | |||||
| General and administrative expenses | $ | 87 | $ | 79 | |||||
| Adjusted general and administrative expenses1 | $ | 82 | $ | 72 | |||||
| Taxes other than on income | $ | 70 | $ | 47 | |||||
| Transportation costs | $ | 19 | $ | 20 | |||||
| Operating income | $ | 98 | $ | 267 | |||||
| Interest and debt expense, net | $ | 25 | $ | 25 | |||||
| Income tax provision | $ | 11 | $ | 70 | |||||
| Deferred income tax provision | $ | 35 | $ | 6 | |||||
| Net income | $ | 64 | $ | 172 | |||||
| Weighted-average common shares outstanding - diluted | 84.4 | 89.4 | |||||||
| Net income per share - diluted | $ | 0.76 | $ | 1.92 | |||||
| Adjusted net income1 | $ | 123 | $ | 98 | |||||
| Adjusted net income per share1- diluted | $ | 1.46 | $ | 1.10 | |||||
| Net cash provided by operating activities | $ | 279 | $ | 165 | |||||
| Adjusted EBITDAX1 | $ | 338 | $ | 324 | |||||
| Free cash flow1 | $ | 188 | $ | 109 | |||||
| Capital investments | $ | 91 | $ | 56 | |||||
| Cash and cash equivalents (as of September 30, 2025 and June 30, 2025, respectively) | $ | 196 | $ | 72 | |||||
| Available cash and cash equivalents | $ | 180 | $ | 56 | |||||
| Restricted cash | $ | 16 | $ | 16 | |||||
Pending Berry Merger
On September 14, 2025, CRC entered into a definitive agreement to combine with Berry in an all-stock transaction (Berry Merger). At closing, Berry shareholders will receive a fixed exchange ratio of 0.0718 shares of CRC common stock for each outstanding share of Berry common stock, resulting in the issuance of approximately 5.6 million CRC shares. This represents a premium of 15% over the closing price of shares of Berry common stock on September 12, 2025.
On October 8, 2025, CRC completed a private offering of $400 million in an aggregate principal amount of 7.000% senior notes due 2034 (2034 Senior Notes). CRC intends to use the proceeds to repay Berry's outstanding debt and for transaction costs, subject to completion of the Berry Merger. The 2034 Senior Notes are subject to a special mandatory redemption in certain circumstances if the Berry Merger does not close prior to March 14, 2026 (subject to up to two three-month extensions by either CRC or Berry).
On October 14, 2025, in connection with the Berry Merger, CRC filed with the Securities and Exchange Commission (SEC) a registration statement on Form S-4, which included a preliminary proxy statement / prospectus. CRC expects the transaction to close in the first quarter of 2026, subject to the satisfaction of customary closing conditions, including required regulatory approvals and receipt of Berry shareholder approval. For more information about this transaction please visit: https://www.crc.com/news-releases/news-release-details/california-resources-corporation-announces-all-stock-combination
Fourth Quarter 2025 Guidance and 2026 Preliminary Outlook
The following table provides select fourth quarter 2025E guidance5. Guidance excludes the financial results of Berry. CRC ran an average of two rigs during the third quarter of 2025 and expects to enter 2026 with four rigs. See Attachment 2 for CRC's fourth quarter 2025E guidance.
| 4Q25E | |
| Net Production (MBoe/d) | 131 - 135 |
| Percentage Oil | 78% |
| Capital Investments ($ millions) | $105 - $125 |
| Adjusted EBITDAX1 ($ millions) | $220 - $260 |
Leon continued: “We expect to enter 2026 with momentum on the heels of an improving regulatory environment, a solid hedge book, and the anticipated closing of the Berry Merger. With that favorable backdrop, we plan to modestly increase capital investments in the Golden State, underpinned by our high-quality, long-life inventory. We'll remain disciplined, prioritizing a robust shareholder return program, maintaining a strong balance sheet, and preserving ample liquidity. At the same time, we'll continue to advance opportunities in power and carbon management that enhance our core business and long-term value proposition supporting sustainable cash flow per share growth through the cycle."
Based on current commodity price and market expectations, CRC plans to average four drilling rigs during 2026. Planned activity is supported by the strength of hedges currently in place. Drilling, completion, and workover capital is estimated to range between $280 to $300 million. The Company expects an entry-to-exit gross production decline of approximately 2%, less than half of its 2025 decline. CRC intends to provide updated full-year 2026 guidance with its fourth quarter and year-end 2025 earnings release. The 2026 drilling program does not include the impact of the pending Berry Merger. CRC retains the flexibility to adjust its 2026 capital plan to reflect changes in commodity prices and other market factors.
Shareholder Returns
CRC is committed to sustainably returning cash to shareholders through dividends and repurchases of its common stock. As of September 30, 2025, CRC had $205 million remaining for share repurchases under its authorized Share Repurchase Program through June 30, 2026.
During the third quarter of 2025, CRC paid dividends of $32 million.
On November 4, 2025, CRC's Board of Directors adjusted the quarterly cash dividend to increase the total annual dividend to $1.62 per share of common stock, payable to shareholders in quarterly increments of $0.405 per share. This represents a 5% increase to the prior dividend per share of CRC common stock. All future dividends and repurchases remain subject to commodity prices, Board approval, and applicable covenants.
On November 4, 2025, CRC's Board of Directors declared a quarterly cash dividend2 of $0.405 per share of common stock, payable to shareholders of record on December 1, 2025. The dividend is expected to be paid on December 15, 2025.
During the nine months ended September 30, 2025, CRC returned $454 million to shareholders2, including $352 million in share repurchases and $102 million in dividends. Since May 2021, the Company has returned more than $1.5 billion to shareholders2, including approximately $1.1 billion in share repurchases and $369 million in dividends.
Balance Sheet and Liquidity
On October 8, 2025, CRC completed a private offering of its 2034 Senior Notes. The net proceeds from this offering plus available cash are expected to be used to repay Berry’s outstanding debt at closing of the Berry Merger and for transaction costs.
On October 10, 2025, CRC redeemed the remaining $122 million of its 2026 Senior Notes at 100% of the principal amount. Following this redemption, none of our 2026 Senior Notes were outstanding.
On October 29, 2025, CRC's $1.5 billion borrowing base was reaffirmed as part of its semi-annual redetermination. In addition, existing and new lenders increased the amount of elected commitments by $300 million to $1.45 billion.
As of September 30, 2025, CRC had $180 million in available cash and cash equivalents3, $974 million of available borrowing capacity under its Revolving Credit Facility (which reflects $1,150 million of borrowing capacity less $176 million of outstanding letters of credit) and liquidity of $1,154 million.
Sustainability
In September 2025, CRC received a “Grade A” certification through MiQ’s Methane Emissions Performance Standard for its production segment operating assets in Ventura County. MiQ is a not-for-profit global leader in methane emissions certification whose mission is to accelerate rapid reductions in methane emissions from the oil and gas sector. CRC earned its ‘Grade A’ certification in 2024 for its Los Angeles Basin assets and remains the only oil and natural gas producer in California and the Rocky Mountain Region to receive MiQ certification. CRC plans to continue working with MiQ to certify its operations across California.
Participation in Upcoming Investor Conferences
CRC is scheduled to participate in the following events in November 2025 to December 2025:
- BofA Securities Global Energy Conference 2025, November 12, Houston, TX
- TD Cowen 2nd Annual Energy Conference, November 18 – 19, New York, NY
- Stephens NASH2025 Conference, November 19 – 20, Nashville, TN
- Wolfe Research Global Oil & Gas Conference, November 19, Virtual
- Mizuho Power, Energy & Infrastructure Conference 2025, December 9, New York, NY
- Capital One Securities 20th Annual Energy Conference, December 9, New Orleans, LA
- Wells Fargo Midstream, Energy and Utilities Symposium, December 10, New York, NY
CRC’s presentation materials will be available on the day of the event on its website. See "Events and Presentations" under the Investor Relations section on www.crc.com.
Conference Call Details
A conference call and webcast are scheduled for 1 p.m. ET (10 a.m. PT) on Wednesday, November 5, 2025. To participate in the call, dial (877) 328-5505 (International calls dial +1 (412) 317-5421) or access via webcast at www.crc.com. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10202512/ffcf85d410. A digital replay of the conference call will be available for approximately 90 days.
1 See Attachment 3 for the non-GAAP financial measures, including but not limited to, operating costs per BOE, adjusted net income (loss), adjusted net income (loss) per share - basic and diluted, adjusted EBITDAX, free cash flow, and adjusted general and administrative expenses including reconciliations to their most directly comparable GAAP measure, where applicable. See Attachment 2 for the 4Q25E estimates of forward-looking non-GAAP measures, including but not limited to, adjusted EBITDAX and adjusted general and administrative expenses, including reconciliations to its most directly comparable GAAP measure. See Attachment 1 for detail of our capital investments.
2 All of CRC’s future quarterly dividends and share repurchases are subject to commodity prices, debt agreement covenants and Board of Directors' approval. The total value of shares purchased excludes excise taxes. Commissions paid on share repurchases were not significant in all periods presented.
3 Excludes restricted cash of $16 million at September 30, 2025.
4 An MOU is a non-binding agreement. The projects and transactions described in an MOU are subject to certain conditions precedent, typically including the negotiation of definitive documents, a final investment decision by the parties and receipt of EPA Class VI permits and other regulatory approvals.
5 4Q25E guidance assumes Brent price of $65.50 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.35 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.
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 CCS and other emissions reducing projects. For more information about CRC, please visit www.crc.com.
About Carbon TerraVault
Carbon TerraVault (CTV), CRC’s carbon management business, is developing services to capture, transport and permanently store CO2 for its customers. CTV is engaged in a series of proposed CCS projects to inject CO2 captured from industrial sources into depleted reservoirs deep underground for permanent sequestration. For more information, visit carbonterravault.com.
Additional Information and Where to Find It
In connection with the Berry Merger, CRC filed with the SEC a registration statement on Form S-4 (the “registration statement”), which became effective on November 3, 2025, and which included a proxy statement of Berry that also constitutes a prospectus of CRC, as well as other relevant documents in connection with the Berry Merger. The definitive proxy statement/prospectus will be sent to the holders of common stock of Berry. Investors and stockholders of CRC and Berry are urged to read the definitive proxy statement/prospectus and any other documents filed or to be filed with the SEC in connection with the Berry Merger when they become available, as they will contain important information about CRC, Berry, the Berry Merger and related matters. The registration statement and definitive proxy statement/prospectus and other documents filed by CRC or Berry with the SEC, when filed, will be available free of charge at the SEC’s website at https://www.sec.gov. Alternatively, investors and stockholders may obtain free copies of documents that are filed or will be filed with the SEC by CRC, including the registration statement and the definitive proxy statement/prospectus, on CRC’s website at https://www.crc.com/investor-relations, and may obtain free copies of documents that are filed or will be filed with the SEC by Berry, including the definitive proxy statement/prospectus, on Berry’s website at https://ir.bry.com/reports-resources. The information included on, or accessible through, CRC’s or Berry’s website is not incorporated by reference into this communication.
No Offer or Solicitation
This communication is not intended to and shall not constitute an offer to sell or the solicitation of an offer to buy any securities, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to appropriate registration or qualification under the securities laws of such jurisdiction. No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.
Participants in Solicitation
CRC and certain of its directors, executive officers and other employees, and Berry and its directors and certain of Berry’s executive officers and other employees, may be deemed to be participants in the solicitation of proxies from Berry’s stockholders in connection with the Berry Merger. A description of participants’ direct or indirect interests, by security holdings or otherwise, are included in the definitive proxy statement/prospectus relating to the Berry Merger. Information regarding CRC’s directors and executive officers is contained in the “Board of Directors and Corporate Governance,” “Compensation Discussion and Analysis,” “Executive Compensation Tables,” “Director Compensation,” “Stock Ownership Information,” and “Proposals Requiring Your Vote – Proposal 1: Election of Directors” sections of CRC’s definitive proxy statement for its 2025 annual meeting of stockholders, filed with the SEC on March 19, 2025; under the heading “Directors, Executive Officers and Corporate Governance” in Part III, Item 10 of CRC’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed with the SEC on March 3, 2025; in Item 5.07 of CRC’s Current Report on Form 8-K filed with the SEC on May 6, 2025; in CRC’s Current Reports on Form 8-K filed with the SEC on June 23, 2025 and November 25, 2024; and under “Our Team” accessed through the “Our Business” link on CRC’s website at https://www.crc.com/our-business/our-team. Information regarding Berry’s directors and executive officers is contained in the “Proposal No. 1—Election of Directors,” “Corporate Governance,” “Executive Officers,” “Executive Compensation – Compensation Discussion and Analysis,” “Director Compensation,” “Security Ownership of Certain Beneficial Owners and Management,” and “Certain Relationships and Related Party Transactions” sections of Berry’s definitive proxy statement for its 2025 annual meeting of stockholders, filed with the SEC on April 7, 2025; under the heading “Directors, Executive Officers and Corporate Governance” in Part III, Item 10 of Berry’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed with the SEC on March 13, 2025; in Item 5.07 of Berry’s Current Report on Form 8-K filed with the SEC on May 22, 2025; in Berry’s Current Reports on Form 8-K filed with the SEC on January 22, 2025 and October 25, 2024; and under “Leadership” accessed through the “About” link on Berry’s website at https://bry.com/about/management/. Additional information regarding ownership of Berry’s securities by its directors and executive officers and of CRC’s securities by its directors and executive officers is included in such persons’ SEC filings on Forms 3, 4 or 5, which are available at https://www.sec.gov/cgi-bin/own-disp?action=getissuer&CIK=0001705873 and https://www.sec.gov/cgi-bin/own-disp?action=getissuer&CIK=0001609253, respectively. These documents and the other SEC filings described in this paragraph may be obtained free of charge as described above under the heading “Additional Information and Where to Find It.”
Forward-Looking Statements
Information set forth in this communication, including financial estimates and statements as to the effects of the Berry Merger, constitute “forward-looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 and other securities laws. All statements other than historical facts are forward-looking statements, and include statements regarding the benefits of the Berry Merger, CRC's future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives and intentions of management for the future. Words such as “expect,” “could,” “may,” “anticipate,” “intend,” “plan,” “ability,” “believe,” “seek,” “see,” “will,” “would,” “estimate,” “forecast,” “target,” “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. These forward-looking statements are based upon the current beliefs and expectations of the management of CRC and are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, projected in, or implied by, such statements.
Although CRC believes the expectations and forecasts reflected in its forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond its control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause CRC’s actual results to be materially different than those expressed in its forward-looking statements are described in its most recent Annual Report on Form 10-K and its other periodic filings with the SEC. These factors include, but are not limited to: fluctuations in commodity prices; production levels and/or pricing by OPEC, OPEC+ or U.S. producers; government policy, war and political conditions and events; integration efforts and projected benefits in connection with the Berry Merger and other acquisitions, the timing, receipt and terms and conditions of any required regulatory approvals of the Berry Merger that could reduce anticipated benefits or cause the parties to abandon the Berry Merger; divestitures and joint ventures; regulatory actions and changes that affect the oil and gas industry generally and us in particular; the efforts of activists to delay prevent oil and gas activities or the development of CRC’s carbon management segment; changes in business strategy and capital plan; lower-than-expected production; changes to estimates of reserves and related future cash flows; the recoverability of resources and unexpected geologic conditions; general economic conditions and trends; results from operations and competition in the industries in which it operates; CRC’s ability to realize the anticipated benefits from prior or future efforts to reduce costs; environmental risks and liability; the benefits contemplated by its energy transition strategies and initiatives; CRC’s ability to successfully identify, develop and finance carbon capture and storage projects, power projects and other renewable energy efforts; future dividends and share repurchases and de-leveraging efforts; and natural disasters, accidents, mechanical failures, power outages, labor difficulties, cybersecurity breaches or attacks or other catastrophic events.
CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the date hereof, and CRC is under no obligation, and expressly disclaims any obligation to update, alter or otherwise revise any forward-looking statements, whether as a result of new information, future events or otherwise. This communication may also contain information from third-party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and does not warrant the accuracy or completeness of such third-party information.
Contacts:
| Joanna Park (Investor Relations) 818-661-3731 Joanna.Park@crc.com |
Daniel Juck (Investor Relations) 818-661-6045 Daniel.Juck@crc.com |
Hailey Bonus (Media) 714-874-7732 Hailey.Bonus@crc.com |
| Attachment 1 | ||||||||||||||||||||
| STATEMENTS OF OPERATIONS, SELECT FINANCIAL INFORMATION | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
| ($ and shares in millions, except per share amounts) |
2025 |
2025 |
2024 |
2025 |
2024 |
|||||||||||||||
| Statements of Operations: | ||||||||||||||||||||
| Revenues | ||||||||||||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 715 | $ | 702 | $ | 870 | $ | 2,231 | $ | 1,711 | ||||||||||
| Net (loss) gain from commodity derivatives | (23 | ) | 157 | 356 | 140 | 290 | ||||||||||||||
| Revenue from marketing of purchased commodities | 58 | 56 | 51 | 178 | 176 | |||||||||||||||
| Electricity sales | 101 | 58 | 69 | 181 | 120 | |||||||||||||||
| Other revenue | 4 | 5 | 7 | 15 | 24 | |||||||||||||||
| Total operating revenues | 855 | 978 | 1,353 | 2,745 | 2,321 | |||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operating costs | 316 | 295 | 311 | 927 | 643 | |||||||||||||||
| General and administrative expenses | 87 | 79 | 106 | 238 | 226 | |||||||||||||||
| Depreciation, depletion and amortization | 123 | 128 | 140 | 382 | 246 | |||||||||||||||
| Asset impairment | 2 | — | — | 2 | 13 | |||||||||||||||
| Taxes other than on income | 70 | 47 | 85 | 187 | 162 | |||||||||||||||
| Costs related to marketing of purchased commodities | 44 | 41 | 43 | 135 | 140 | |||||||||||||||
| Electricity generation expenses | 11 | 5 | 9 | 26 | 31 | |||||||||||||||
| Transportation costs | 19 | 20 | 23 | 59 | 60 | |||||||||||||||
| Accretion expense | 28 | 28 | 31 | 85 | 56 | |||||||||||||||
| Net loss on natural gas purchase derivatives | 27 | 3 | 9 | 24 | 11 | |||||||||||||||
| Measurement period adjustments, net | — | — | — | 1 | — | |||||||||||||||
| Other operating expenses, net | 29 | 65 | 78 | 127 | 188 | |||||||||||||||
| Total operating expenses | 756 | 711 | 835 | 2,193 | 1,776 | |||||||||||||||
| Net (loss) gain on asset divestitures | (1 | ) | — | — | (1 | ) | 7 | |||||||||||||
| Operating Income | 98 | 267 | 518 | 551 | 552 | |||||||||||||||
| Non-Operating (Expenses) Income | ||||||||||||||||||||
| Interest and debt expense, net | (25 | ) | (25 | ) | (29 | ) | (77 | ) | (59 | ) | ||||||||||
| Loss from investment in unconsolidated subsidiaries | (2 | ) | — | (2 | ) | (3 | ) | (9 | ) | |||||||||||
| Loss on early extinguishment of debt | — | — | (5 | ) | (1 | ) | (5 | ) | ||||||||||||
| Other non-operating income (expense), net | 4 | — | 1 | 9 | (4 | ) | ||||||||||||||
| Income Before Income Taxes | 75 | 242 | 483 | 479 | 475 | |||||||||||||||
| Income tax provision | (11 | ) | (70 | ) | (138 | ) | (128 | ) | (132 | ) | ||||||||||
| Net Income | $ | 64 | $ | 172 | $ | 345 | $ | 351 | $ | 343 | ||||||||||
| Net income per share - basic | $ | 0.76 | $ | 1.93 | $ | 3.86 | $ | 4.00 | $ | 4.54 | ||||||||||
| Net income per share - diluted | $ | 0.76 | $ | 1.92 | $ | 3.78 | $ | 3.97 | $ | 4.42 | ||||||||||
| Adjusted net income | $ | 123 | $ | 98 | $ | 137 | $ | 319 | $ | 233 | ||||||||||
| Adjusted net income per share - basic | $ | 1.47 | $ | 1.10 | $ | 1.53 | $ | 3.63 | $ | 3.09 | ||||||||||
| Adjusted net income per share - diluted | $ | 1.46 | $ | 1.10 | $ | 1.50 | $ | 3.61 | $ | 3.00 | ||||||||||
| Weighted-average common shares outstanding - basic | 83.7 | 89.0 | 89.4 | 87.8 | 75.5 | |||||||||||||||
| Weighted-average common shares outstanding - diluted | 84.4 | 89.4 | 91.2 | 88.4 | 77.6 | |||||||||||||||
| Effective tax rate | 15 | % | 29 | % | 29 | % | 27 | % | 28 | % | ||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
| ($ in millions) |
2025 |
2025 |
2024 |
2025 |
2024 |
|||||||||||||||
| Cash Flow Data: | ||||||||||||||||||||
| Net cash provided by operating activities | $ | 279 | $ | 165 | $ | 220 | $ | 630 | $ | 404 | ||||||||||
| Net cash used in investing activities | $ | (87 | ) | $ | (51 | ) | $ | (928 | ) | $ | (217 | ) | $ | (1,010 | ) | |||||
| Net cash (used in) provided by financing activities | $ | (68 | ) | $ | (256 | ) | $ | (82 | ) | $ | (589 | ) | $ | 351 | ||||||
| September 30, | December 31, | |||||||||||||||||||
| ($ in millions) |
2025 |
2024 |
||||||||||||||||||
| Select Balance Sheet Information: | ||||||||||||||||||||
| Total current assets | $ | 812 | $ | 1,024 | ||||||||||||||||
| Property, plant and equipment, net | $ | 5,530 | $ | 5,680 | ||||||||||||||||
| Deferred tax asset | $ | 27 | $ | 73 | ||||||||||||||||
| Total current liabilities | $ | 917 | $ | 980 | ||||||||||||||||
| Long-term debt, net | $ | 889 | $ | 1,132 | ||||||||||||||||
| Noncurrent asset retirement obligations | $ | 965 | $ | 995 | ||||||||||||||||
| Deferred tax liability | $ | 212 | $ | 113 | ||||||||||||||||
| Total stockholders' equity | $ | 3,443 | $ | 3,538 | ||||||||||||||||
| GAINS AND LOSSES FROM COMMODITY DERIVATIVES | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter |
Nine Months |
Nine Months | ||||||||||||||||
| ($ millions) |
2025 |
2025 |
2024 |
2025 |
2024 |
|||||||||||||||
| Non-cash commodity derivative gain (loss) | $ | (32 | ) | $ | 140 | $ | 373 | $ | 130 | $ | 325 | |||||||||
| Net received (paid) on settled commodity derivatives | 9 | 17 | (17 | ) | 10 | (35 | ) | |||||||||||||
| Net gain (loss) from commodity derivatives | $ | (23 | ) | $ | 157 | $ | 356 | $ | 140 | $ | 290 | |||||||||
| Non-cash derivative loss (gain) | $ | 24 | $ | (4 | ) | $ | (3 | ) | $ | 2 | $ | (7 | ) | |||||||
| Net paid on settled commodity derivatives | 3 | 7 | 12 | 22 | 18 | |||||||||||||||
| Net loss on natural gas purchase derivatives | $ | 27 | $ | 3 | $ | 9 | $ | 24 | $ | 11 | ||||||||||
| CAPITAL INVESTMENTS | ||||||||||||||||||||
|
3rd Quarter |
2nd Quarter |
3rd Quarter |
Nine Months |
Nine Months |
||||||||||||||||
| ($ millions) |
2025 |
2025 |
2024 |
2025 |
2024 |
|||||||||||||||
| Exploration | $ | 1 | $ | — | $ | — | $ | 1 | $ | — | ||||||||||
| Facilities | 28 | 17 | 36 | 53 | 67 | |||||||||||||||
| Drilling and completions | 26 | 19 | 19 | 60 | 52 | |||||||||||||||
| Workovers | 17 | 15 | 19 | 51 | 37 | |||||||||||||||
| Oil and natural gas segment | 72 | 51 | 74 | 165 | 156 | |||||||||||||||
| Carbon management segment | 15 | 5 | 4 | 22 | 6 | |||||||||||||||
| Corporate and other | 4 | — | 1 | 15 | 5 | |||||||||||||||
| Total capital investment | $ | 91 | $ | 56 | $ | 79 | $ | 202 | $ | 167 | ||||||||||
| LIQUIDITY | ||||||||
| Management uses a measure called liquidity, which is defined as available cash and available borrowing capacity under our Revolving Credit Facility. CRC believes this measure provides a more comprehensive assessment of the Company’s immediate access to capital than cash alone and reflects management’s emphasis on maintaining financial flexibility and prudent liquidity risk management. | ||||||||
| ($ millions) | September 30, 2025 | December 31, 2024 | ||||||
| Available cash and cash equivalents(1) | $ | 180 | $ | 354 | ||||
| Revolving credit facility: | ||||||||
| Borrowing capacity | 1,150 | 1,150 | ||||||
| Outstanding letters of credit | (176 | ) | (167 | ) | ||||
| Availability | $ | 974 | $ | 983 | ||||
| Liquidity | $ | 1,154 | $ | 1,337 | ||||
| (1) Excludes restricted cash of $16 million and $18 million at September 30, 2025 and December 31, 2024, respectively. | ||||||||
| Attachment 2 | ||||||
| CRC GUIDANCE |
Consolidated 4Q25E |
Oil and Natural Gas Segment |
Carbon Management Segment |
|||
| Net production (MBoe/d) | 131 - 135 | |||||
| Net oil production (%) | 78% | |||||
| Operating costs ($ millions) | $300 - $320 | $300 - $320 | ||||
| General and administrative expenses ($ millions) | $78 - $86 | $8 - $12 | $2 - $4 | |||
| Adjusted general and administrative expenses ($ millions) | $72 - $80 | $8 - $12 | $2 - $4 | |||
| Depreciation, depletion and amortization ($ millions) | $128 - $132 | $111 - $115 | ||||
| Capital investments ($ millions) | $105 - $125 | $85 - $105 | $15 - $20 | |||
| Adjusted EBITDAX ($ millions) | $220 - $260 | $284 - $309 | ($19) - ($15) | |||
| Margin from purchased commodities ($ millions) (1) | $14 - $18 | |||||
| Electricity margin ($ millions) (2) | $27 - $33 | |||||
| Other operating expenses net of other revenue ($ millions) (3) | $15 - $20 | $12 - $16 | ||||
| Transportation costs ($ millions) | $20 - $26 | $9 - $13 | ||||
| Taxes other than on income ($ millions) | $60 - $65 | $48 - $52 | ||||
| Interest and debt expense ($ millions) | $30 - $35 | |||||
| Other Assumptions: | ||||||
| Brent ($/Bbl) | $65.50 | |||||
| NYMEX ($/Mcf) | $3.35 | |||||
| Price realization oil - % of Brent: | 94% - 100% | |||||
| Price realization NGLs - % of Brent: | 60% - 70% | |||||
| Price realization natural gas - % of NYMEX: | 100% - 105% | |||||
| Deferred income taxes | (120)% - (130)% | |||||
| Effective tax rate | 27% | |||||
(1) Margin from purchased commodities is calculated as the difference between revenue from marketing of purchased commodities and costs related to marketing of purchased commodities, and excludes costs of transportation.
(2) Electricity margin is calculated as the difference between electricity sales and electricity generation expenses.
(3) Other operating revenue and expenses, net is calculated as the difference between other revenue and other operating expenses, net and includes exploration expense and CMB expenses. CMB expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.
See Attachment 3 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition.
FORWARD LOOKING NON-GAAP RECONCILIATIONS
A reconciliation of the non-GAAP measure of segment adjusted EBITDAX cannot be reconciled to the comparable measure of operating cash flow prepared in accordance with GAAP without unreasonable effort. We have included a reconciliation of the GAAP measure of segment profit to segment adjusted EBITDAX.
|
4Q25E |
||||||||||||||||||||||||
| Consolidated |
Oil and Natural Gas Segment |
Carbon Management Segment |
||||||||||||||||||||||
| ($ millions) | Low | High | Low |
High |
Low |
High |
||||||||||||||||||
| General and administrative expenses | $ | 78 | $ | 86 | $ | 8 | $ | 12 | $ | 2 | $ | 4 | ||||||||||||
| Equity-settled stock-based compensation | (6 | ) | (6 | ) | — | — | — | — | ||||||||||||||||
| Estimated adjusted general and administrative expenses | $ | 72 | $ | 80 | $ | 8 | $ | 12 | $ | 2 | $ | 4 | ||||||||||||
|
Consolidated |
||||||||
|
4Q25E |
||||||||
| ($ millions) | Low | High |
||||||
| Net income | $ | 15 | $ | 27 | ||||
| Interest and debt expense | 30 | 35 | ||||||
| Interest income | (4 | ) | — | |||||
| Depreciation, depletion and amortization | 128 | 132 | ||||||
| Income taxes | 4 | 10 | ||||||
| Exploration expense | 1 | 1 | ||||||
| Loss from investment on unconsolidated subsidiaries | — | 2 | ||||||
| Unusual, infrequent and other items | 14 | 18 | ||||||
| Other non-cash items | ||||||||
| Accretion expense | 26 | 29 | ||||||
| Stock-settled compensation | 6 | 6 | ||||||
| Estimated adjusted EBITDAX | $ | 220 | $ | 260 | ||||
| Net cash provided by operating activities | $ | 180 | $ | 192 | ||||
| Cash interest | 34 | 43 | ||||||
| Cash income taxes | 4 | 10 | ||||||
| Working capital changes | 2 | 15 | ||||||
| Estimated adjusted EBITDAX | $ | 220 | $ | 260 | ||||
|
Oil and Natural Gas Segment |
||||||||
|
4Q25E |
||||||||
| ($ millions) | Low |
High |
||||||
| Segment profit | $ | 145 | $ | 155 | ||||
| Depreciation, depletion and amortization | 111 | 115 | ||||||
| Unusual, infrequent and other items | 3 | 9 | ||||||
| Other non-cash items | ||||||||
| Accretion expense | 25 | 30 | ||||||
| Estimated adjusted EBITDAX | $ | 284 | $ | 309 | ||||
| Carbon Management Segment | ||||||||
| 4Q25E | ||||||||
| ($ millions) | Low | High | ||||||
| Segment loss | $ | (17 | ) | $ | (27 | ) | ||
| Interest and debt expense, net | 1 | 5 | ||||||
| Loss from investment on unconsolidated subsidiary | 1 | 3 | ||||||
| Estimated adjusted EBITDAX | $ | (15 | ) | $ | (19 | ) | ||
| Consolidated | ||||||||
| 4Q25E | ||||||||
| ($ millions) | Low | High | ||||||
| Revenue from marketing of purchased commodities | $ | 50 | $ | 70 | ||||
| Costs related to marketing of purchased commodities | (38 | ) | (50 | ) | ||||
| Margin from purchased commodities | $ | 12 | $ | 20 | ||||
| Consolidated | ||||||||
| 4Q25E | ||||||||
| ($ millions) | Low | High | ||||||
| Electricity sales | $ | 38 | $ | 50 | ||||
| Electricity generation expenses | (10 | ) | (16 | ) | ||||
| Electricity margin | $ | 28 | $ | 34 | ||||
| Consolidated | ||||||||
| 4Q25E | ||||||||
| ($ millions) | Low | High | ||||||
| Other operating expenses, net | $ | 10 | $ | 30 | ||||
| Other revenue | (1 | ) | (5 | ) | ||||
| Operating expenses net of other revenue | $ | 9 | $ | 25 | ||||
| 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 net income (loss) per share, adjusted EBITDAX, adjusted EBITDAX per Boe, adjusted EBITDAX for the oil and natural gas segment, adjusted EBITDAX for the carbon management business, free cash flow, adjusted general and administrative expenses and adjusted G&A per Boe. These measures are also widely used by the industry, the investment community and CRC's lenders. Although these are non-GAAP measures, the amounts included in the calculations were computed in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing CRC's financial performance, such as CRC's cost of capital and tax structure, as well as the effect of acquisition and development costs of CRC's assets. Management believes that the non-GAAP measures presented, when viewed in combination with CRC's financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the Company's performance. The non-GAAP measures presented herein may not be comparable to other similarly titled measures of other companies. Below are additional disclosures regarding each of these non-GAAP measures, including reconciliations to their most directly comparable GAAP measure where applicable. |
| ADJUSTED NET INCOME (LOSS) | ||||||||||||||||||||
| Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. CRC defines adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing CRC's financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income and net income attributable to common stock per share to the non-GAAP financial measures of adjusted net income and adjusted net income per share. | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
| ($ millions, except per share amounts) |
2025 |
2025 |
2024 |
2025 |
2024 |
|||||||||||||||
| Net income | $ | 64 | $ | 172 | $ | 345 | $ | 351 | $ | 343 | ||||||||||
| Unusual, infrequent and other items: | ||||||||||||||||||||
| Non-cash derivative loss (gain) on Brent based commodity contracts | 32 | (140 | ) | (373 | ) | (130 | ) | (325 | ) | |||||||||||
| Non-cash derivative loss (gain) on natural gas derivative contracts | 24 | (4 | ) | (3 | ) | 2 | (7 | ) | ||||||||||||
| Asset impairment | 2 | — | — | 2 | 13 | |||||||||||||||
| Severance and termination costs | — | 6 | 27 | 8 | 28 | |||||||||||||||
| Merger-related costs | 6 | 1 | 30 | 10 | 56 | |||||||||||||||
| Increased power and fuel costs due to power plant maintenance | — | — | 8 | — | 44 | |||||||||||||||
| Net loss (gain) on asset divestitures | 1 | — | — | 1 | (7 | ) | ||||||||||||||
| Loss on early extinguishment of debt | — | — | 5 | 1 | 5 | |||||||||||||||
| Offshore platform expense | 5 | 2 | 1 | 7 | 3 | |||||||||||||||
| Litigation and settlement related expenses | 1 | 25 | — | 26 | 7 | |||||||||||||||
| Measurement period adjustments | — | — | — | 1 | — | |||||||||||||||
| Other, net | 11 | 7 | 8 | 27 | 22 | |||||||||||||||
| Total unusual, infrequent and other items | 82 | (103 | ) | (297 | ) | (45 | ) | (161 | ) | |||||||||||
| Income tax (benefit) provision of adjustments at the blended tax rate | (23 | ) | 29 | 89 | 13 | 51 | ||||||||||||||
| Adjusted net income | $ | 123 | $ | 98 | $ | 137 | $ | 319 | $ | 233 | ||||||||||
| Net income (loss) per share – basic | $ | 0.76 | $ | 1.93 | $ | 3.86 | $ | 4.00 | $ | 4.54 | ||||||||||
| Net income (loss) per share – diluted | $ | 0.76 | $ | 1.92 | $ | 3.78 | $ | 3.97 | $ | 4.42 | ||||||||||
| Adjusted net income per share – basic | $ | 1.47 | $ | 1.10 | $ | 1.53 | $ | 3.63 | $ | 3.09 | ||||||||||
| Adjusted net income per share – diluted | $ | 1.46 | $ | 1.10 | $ | 1.50 | $ | 3.61 | $ | 3.00 | ||||||||||
| ADJUSTED EBITDAX | ||||||||||||||||||||
| CRC defines adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. CRC believes this measure provides useful information in assessing its financial condition, results of operations and cash flows and is widely used by the industry, the investment community and its lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing CRC’s financial performance, such as its cost of capital and tax structure, as well as depreciation, depletion and amortization of CRC's assets. This measure should be read in conjunction with the information contained in CRC’s financial statements prepared in accordance with GAAP. A version of adjusted EBITDAX is a material component of certain of its financial covenants under CRC's Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. The following table represents a reconciliation of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX. CRC has included non-GAAP measures of adjusted EBITDAX for its oil and gas segment and its carbon management segment. Management believes these segment non-GAAP measures are useful for investors to understand the results of the oil and gas business and its developing carbon management business. | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
| ($ millions, except per BOE amounts) |
2025 |
2025 |
2024 |
2025 |
2024 |
|||||||||||||||
| Net income | $ | 64 | $ | 172 | $ | 345 | $ | 351 | $ | 343 | ||||||||||
| Interest and debt expense | 25 | 25 | 29 | 77 | 59 | |||||||||||||||
| Depreciation, depletion and amortization | 123 | 128 | 140 | 382 | 246 | |||||||||||||||
| Income tax provision | 11 | 70 | 138 | 128 | 132 | |||||||||||||||
| Exploration expense | — | 1 | 1 | 1 | 2 | |||||||||||||||
| Interest income | (1 | ) | (2 | ) | (1 | ) | (6 | ) | (15 | ) | ||||||||||
| Loss from investment in unconsolidated subsidiaries | 2 | — | — | 3 | — | |||||||||||||||
| Unusual, infrequent and other items(1) | 82 | (103 | ) | (297 | ) | (45 | ) | (161 | ) | |||||||||||
| Non-cash items | ||||||||||||||||||||
| Accretion expense | 28 | 28 | 31 | 85 | 56 | |||||||||||||||
| Stock-based compensation | 5 | 7 | 6 | 18 | 17 | |||||||||||||||
| Taxes related to acquisition accounting and other | — | — | 10 | — | 10 | |||||||||||||||
| Pension and post-retirement benefits | (1 | ) | (2 | ) | — | (4 | ) | 1 | ||||||||||||
| Adjusted EBITDAX | $ | 338 | $ | 324 | $ | 402 | $ | 990 | $ | 690 | ||||||||||
| Net cash provided by operating activities | $ | 279 | $ | 165 | $ | 220 | $ | 630 | $ | 404 | ||||||||||
| Cash interest payments | 6 | 39 | 24 | 56 | 46 | |||||||||||||||
| Cash interest received | (1 | ) | (2 | ) | (1 | ) | (6 | ) | (15 | ) | ||||||||||
| Cash income taxes | 6 | 39 | 29 | 45 | 55 | |||||||||||||||
| Exploration expenditures | — | 1 | 1 | 1 | 2 | |||||||||||||||
| Adjustments to working capital changes | 48 | 82 | 129 | 264 | 198 | |||||||||||||||
| Adjusted EBITDAX | $ | 338 | $ | 324 | $ | 402 | $ | 990 | $ | 690 | ||||||||||
| Net income per Boe | $ | 5.09 | $ | 13.78 | $ | 25.91 | $ | 9.31 | $ | 12.65 | ||||||||||
| Adjusted EBITDAX per Boe | $ | 26.90 | $ | 25.95 | $ | 30.19 | $ | 26.25 | $ | 25.44 | ||||||||||
| (1)See Adjusted Net Income (Loss) reconciliation. | ||||||||||||||||||||
| SEGMENT ADJUSTED EBITDAX | ||||||||||||||||||||
| CRC defines segments adjusted EBITDAX as segment profit adjusted for depreciation, depletion and amortization; exploration expense, other unusual, infrequent and out-of-period items and other non-cash items. CRC believes this segment measure provides useful information in assessing the financial results of each segment. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. This measure should be read in conjunction with Note 16Segment Informationin CRC’s 2024 Annual Report. A reconciliation of the non-GAAP measure of segment adjusted EBITDAX cannot be reconciled to the comparable measure of operating cash flow prepared in accordance with GAAP without unreasonable effort. | ||||||||||||||||||||
| Oil & Natural Gas Segment | 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||||||||||||
| ($ millions, except per BOE amounts) |
2025 |
2025 |
2024(1) |
2025 |
2024 |
|||||||||||||||
| Segment profit | $ | 182 | $ | 194 | $ | 298 | $ | 642 | $ | 547 | ||||||||||
| Depreciation, depletion and amortization | 118 | 121 | 129 | 365 | 225 | |||||||||||||||
| Exploration expense | — | 1 | 1 | 1 | 2 | |||||||||||||||
| Accretion expense | 28 | 28 | 31 | 85 | 56 | |||||||||||||||
| Adjusted income items | 4 | 2 | 15 | 7 | 57 | |||||||||||||||
| Adjusted EBITDAX - Oil and Natural Gas | $ | 332 | $ | 346 | $ | 474 | $ | 1,100 | $ | 887 | ||||||||||
| Carbon Management Segment | ||||||||||||||||||||
| Segment loss | $ | (21 | ) | $ | (20 | ) | $ | (25 | ) | $ | (66 | ) | $ | (63 | ) | |||||
| Interest on contingent liability (related to Carbon TerraVault JV) | 3 | 2 | 3 | 8 | 6 | |||||||||||||||
| Loss from investment in unconsolidated subsidiaries | 2 | 1 | 3 | 4 | 3 | |||||||||||||||
| Adjusted income items | 2 | — | — | 2 | 1 | |||||||||||||||
| Adjusted EBITDAX - Carbon Management | $ | (14 | ) | $ | (17 | ) | $ | (19 | ) | $ | (52 | ) | $ | (53 | ) | |||||
| (1)Certain amounts related to the third quarter of 2024 previously reported in the Q4 2024 earnings release have been corrected. These corrections related to classification of expenditures by segment and have no material impact on the company's overall financial position. | ||||||||||||||||||||
| FREE CASH FLOW | ||||||||||||||||||||
| Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow. | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
| ($ millions) |
2025 |
2025 |
2024 |
2025 |
2024 |
|||||||||||||||
| Net cash provided by operating activities | $ | 279 | $ | 165 | $ | 220 | $ | 630 | $ | 404 | ||||||||||
| Capital investments | (91 | ) | (56 | ) | (79 | ) | (202 | ) | (167 | ) | ||||||||||
| Free cash flow | $ | 188 | $ | 109 | $ | 141 | $ | 428 | $ | 237 | ||||||||||
| ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES | ||||||||||||||||||||
| Management uses a measure called adjusted general and administrative (G&A) expenses and adjusted G&A per BOE to provide useful information to investors interested in comparing CRC's costs between periods and performance to its peers. | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
| ($ millions) |
2025 |
2025 |
2024 |
2025 |
2024 |
|||||||||||||||
| General and administrative expenses | $ | 87 | $ | 79 | $ | 106 | $ | 238 | $ | 226 | ||||||||||
| Stock-based compensation | (5 | ) | (7 | ) | (6 | ) | (18 | ) | (17 | ) | ||||||||||
| Information technology infrastructure | — | — | — | — | (3 | ) | ||||||||||||||
| Accelerated vesting | — | — | (9 | ) | — | (9 | ) | |||||||||||||
| Retention awards | — | — | (2 | ) | — | (2 | ) | |||||||||||||
| Other | — | — | — | — | (1 | ) | ||||||||||||||
| Adjusted G&A expenses | $ | 82 | $ | 72 | $ | 89 | $ | 220 | $ | 194 | ||||||||||
| G&A per BOE | $ | 6.92 | $ | 6.33 | $ | 7.96 | $ | 6.31 | $ | 8.33 | ||||||||||
| Adjusted G&A per BOE | $ | 6.52 | $ | 5.77 | $ | 6.68 | $ | 5.83 | $ | 7.15 | ||||||||||
| MARGIN FROM PURCHASED COMMODITIES | ||||||||||||||||||||
| Management uses a measure called margin from purchased commodities, which is calculated as the difference between revenue from purchased commodities and costs related to purchased commodities and exudes transportation costs. | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
| ($ millions) |
2025 |
2025 |
2024 |
2025 |
2024 |
|||||||||||||||
| Revenue from purchased commodities | $ | 58 | $ | 56 | $ | 51 | $ | 178 | $ | 176 | ||||||||||
| Costs related to purchased commodities | (44 | ) | (41 | ) | (43 | ) | (135 | ) | (140 | ) | ||||||||||
| Margin from purchased commodities | $ | 14 | $ | 15 | $ | 8 | $ | 43 | $ | 36 | ||||||||||
| ELECTRICITY MARGIN | ||||||||||||||||||||
| Management uses a measure called electricity margin, which is calculated as the difference between electricity sales and electricity generation expenses. | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
| ($ millions) |
2025 |
2025 |
2024 |
2025 |
2024 |
|||||||||||||||
| Electricity sales | $ | 101 | $ | 58 | $ | 69 | $ | 181 | $ | 120 | ||||||||||
| Electricity generation expenses | (11 | ) | (5 | ) | (9 | ) | (26 | ) | (31 | ) | ||||||||||
| Electricity margin | $ | 90 | $ | 53 | $ | 60 | $ | 155 | $ | 89 | ||||||||||
| OTHER OPERATING EXPENSES NET OF OTHER REVENUE | ||||||||||||||||||||
| Management uses a measure called other operating expenses net of other revenue, which is calculated as the difference between other operating expenses, net and other revenue. | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
| ($ millions) |
2025 |
2025 |
2024 |
2025 |
2024 |
|||||||||||||||
| Other operating expenses, net | $ | 29 | $ | 65 | $ | 78 | $ | 127 | $ | 188 | ||||||||||
| Other revenue | (4 | ) | (5 | ) | (7 | ) | (15 | ) | (24 | ) | ||||||||||
| Other operating expenses net of other revenue | $ | 25 | $ | 60 | $ | 71 | $ | 112 | $ | 164 | ||||||||||
|
Attachment 4 | |||||||||||||||
| PRODUCTION STATISTICS | |||||||||||||||
|
3rd Quarter |
2nd Quarter |
3rd Quarter |
Nine Months |
Nine Months |
|||||||||||
| Net Production Per Day |
2025 |
2025 |
2024 |
2025 |
2024 |
||||||||||
| Oil (MBbl/d) | |||||||||||||||
| San Joaquin Basin | 81 | 83 | 90 | 83 | 50 | ||||||||||
| Los Angeles Basin | 17 | 17 | 17 | 17 | 17 | ||||||||||
| Other Basins | 9 | 9 | 6 | 9 | 2 | ||||||||||
| Total | 107 | 109 | 113 | 109 | 69 | ||||||||||
| NGLs (MBbl/d) | |||||||||||||||
| San Joaquin Basin | 10 | 10 | 10 | 10 | 11 | ||||||||||
| Other Basins | — | — | 1 | — | — | ||||||||||
| Total | 10 | 10 | 11 | 10 | 11 | ||||||||||
| Natural Gas (MMcf/d) | |||||||||||||||
| San Joaquin Basin | 103 | 96 | 111 | 100 | 99 | ||||||||||
| Los Angeles Basin | 1 | 1 | 1 | 1 | 1 | ||||||||||
| Sacramento Basin | 11 | 12 | 13 | 12 | 14 | ||||||||||
| Other Basins | 3 | 2 | 1 | 2 | — | ||||||||||
| Total | 118 | 111 | 126 | 115 | 114 | ||||||||||
| Total Net Production (MBoe/d) | 137 | 137 | 145 | 138 | 99 | ||||||||||
| Gross Operated and Net Non-Operated |
3rd Quarter |
2nd Quarter |
3rd Quarter |
Nine Months |
Nine Months |
||||||||||
| Production Per Day |
2025 |
2025 |
2024 |
2025 |
2024 |
||||||||||
| Oil (MBbl/d) | |||||||||||||||
| San Joaquin Basin | 86 | 89 | 96 | 88 | 54 | ||||||||||
| Los Angeles Basin | 21 | 21 | 23 | 22 | 24 | ||||||||||
| Other Basins | 11 | 11 | 8 | 11 | 3 | ||||||||||
| Total | 118 | 121 | 127 | 121 | 81 | ||||||||||
| NGLs (MBbl/d) | |||||||||||||||
| San Joaquin Basin | 11 | 11 | 11 | 11 | 11 | ||||||||||
| Total | 11 | 11 | 11 | 11 | 11 | ||||||||||
| Natural Gas (MMcf/d) | |||||||||||||||
| San Joaquin Basin | 133 | 134 | 137 | 134 | 130 | ||||||||||
| Los Angeles Basin | 6 | 6 | 7 | 6 | 7 | ||||||||||
| Sacramento Basin | 14 | 14 | 16 | 14 | 17 | ||||||||||
| Other Basins | 4 | 4 | 3 | 4 | 1 | ||||||||||
| Total | 157 | 158 | 163 | 158 | 155 | ||||||||||
| Total Gross Production (MBoe/d) | 155 | 158 | 165 | 158 | 118 | ||||||||||
|
Attachment 5 | ||||||||||||||||||||
| PRICE STATISTICS | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
|
2025 |
2025 |
2024 |
2025 |
2024 |
||||||||||||||||
| Oil ($ per Bbl) | ||||||||||||||||||||
| Realized price with derivative settlements | $ | 67.04 | $ | 66.73 | $ | 75.38 | $ | 68.61 | $ | 77.10 | ||||||||||
| Realized price without derivative settlements | $ | 66.32 | $ | 65.07 | $ | 77.10 | $ | 68.34 | $ | 79.15 | ||||||||||
| NGLs ($/Bbl) | $ | 41.04 | $ | 42.41 | $ | 45.77 | $ | 46.10 | $ | 47.77 | ||||||||||
| Natural gas ($/Mcf) | ||||||||||||||||||||
| Realized price with derivative settlements | $ | 3.47 | $ | 2.79 | $ | 2.68 | $ | 3.46 | $ | 2.76 | ||||||||||
| Realized price without derivative settlements | $ | 3.47 | $ | 2.79 | $ | 2.68 | $ | 3.46 | $ | 2.76 | ||||||||||
| Index Prices | ||||||||||||||||||||
| Brent oil ($/Bbl) | $ | 68.13 | $ | 66.76 | $ | 78.54 | $ | 69.94 | $ | 81.79 | ||||||||||
| WTI oil ($/Bbl) | $ | 64.93 | $ | 63.74 | $ | 75.09 | $ | 66.70 | $ | 77.54 | ||||||||||
| NYMEX average monthly settled price ($/MMBtu) | $ | 3.07 | $ | 3.44 | $ | 2.16 | $ | 3.39 | $ | 2.10 | ||||||||||
| Realized Prices as Percentage of Index Prices | ||||||||||||||||||||
| Oil with derivative settlements as a percentage of Brent | 98 | % | 100 | % | 96 | % | 98 | % | 94 | % | ||||||||||
| Oil without derivative settlements as a percentage of Brent | 97 | % | 97 | % | 98 | % | 98 | % | 97 | % | ||||||||||
| Oil with derivative settlements as a percentage of WTI | 103 | % | 105 | % | 100 | % | 103 | % | 99 | % | ||||||||||
| Oil without derivative settlements as a percentage of WTI | 102 | % | 102 | % | 103 | % | 102 | % | 102 | % | ||||||||||
| NGLs as a percentage of Brent | 60 | % | 64 | % | 58 | % | 66 | % | 58 | % | ||||||||||
| NGLs as a percentage of WTI | 63 | % | 67 | % | 61 | % | 69 | % | 62 | % | ||||||||||
| Natural gas with derivative settlements as a percentage of NYMEX contract month average | 113 | % | 81 | % | 124 | % | 102 | % | 131 | % | ||||||||||
| Natural gas without derivative settlements as a percentage of NYMEX contract month average | 113 | % | 81 | % | 124 | % | 102 | % | 131 | % | ||||||||||
|
Attachment 6 | ||||||||||
| THIRD QUARTER 2025 DRILLING ACTIVITY | ||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | |||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | |||||
| Development Wells | ||||||||||
| Primary | 2 | — | — | — | 2 | |||||
| Waterflood | 6 | — | — | — | 6 | |||||
| Steamflood | 12 | — | — | — | 12 | |||||
| Total(1) | 20 | — | — | — | 20 | |||||
| NINE MONTHS 2025 DRILLING ACTIVITY | ||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | |||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | |||||
| Development Wells | ||||||||||
| Primary | 6 | — | — | — | 6 | |||||
| Waterflood | 29 | — | — | — | 29 | |||||
| Steamflood | 12 | — | — | — | 12 | |||||
| Total(1) | 47 | — | — | — | 47 | |||||
| (1)Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | ||||||||||
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