California Resources Reports First Quarter 2025 Financial and Operating Results
Returned $258 Million to Stakeholders, Maintained Balance Sheet Strength, Delivered Flat Quarter-Over-Quarter Total Net Production
Company Reaffirms its 2025 Production, Capital Investment and Adjusted EBITDAX Guidance
LONG BEACH, Calif., May 06, 2025 (GLOBE NEWSWIRE) — California Resources Corporation (NYSE: CRC) today reported financial and operating results for the first quarter of 2025. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Wednesday, May 7, 2025. Participation details can be found within this release. Supplemental slides are available on CRC’s website at www.crc.com.
Highlights
- Reported net income of $115 million, adjusted net income1 of $98 million and adjusted EBITDAX1 of $328 million
- Generated $186 million of net cash provided by operating activities and $252 million of operating cash flow before net changes in operating assets and liabilities1
- Generated $131 million in free cash flow1
- Delivered average net production of 141 thousand barrels of oil equivalent per day (MBoe/d) (79% oil), flat quarter-over-quarter production, with drilling, completions and workover capital of $34 million
- Returned $258 million to stakeholders2, including $100 million in share repurchases, $35 million in dividends and $123 million in debt repurchases
- Realized $173 million of the Aera-related merger synergies; on track to realize $185 million by the end of 2025 and the remainder in early 2026
- Exited the first quarter of 2025 with $199 million in available cash3, $983 million in available borrowing capacity and $1,182 million of liquidity1, 3
- Targeting first carbon dioxide (CO₂) injection at the CTV I – 26R storage reservoir from CRC’s carbon capture and storage (CCS) project at its Elk Hills Cryogenic Gas Plant by year-end 2025. See Carbon TerraVault’s First Quarter 2025 Update for additional information
“We delivered a strong start to 2025, executing our business plan that allows us to create value in a volatile macro environment while returning a record quarterly amount of capital to shareholders,” said CRC President and CEO Francisco Leon. “Our integrated strategy—anchored by low-decline conventional assets, a scalable carbon management platform, and power solutions—positions us to generate sustainable free cash flow across cycles. We are pleased with the Aera integration as the team works to realize the $185 million of synergies through the balance of this year. With 70% of our oil production hedged for 2025, a right-sized cost structure following the Aera merger, and expected progress in our CCS and power initiatives, we remain confident in our performance in 2025. We are building a different kind of energy company—one that’s resilient, returns-focused, and critical to California’s decarbonization.”
First Quarter 2025 Financial Results
| Selected Production, Price Information and Results of Operations | 1st Quarter | 4th Quarter | |||||||
| ($ in millions) | 2025 | 2024 | |||||||
| Net oil production per day (MBbl/d) | 111 | 112 | |||||||
| Realized oil price with derivative settlements ($ per Bbl) | $ | 72.01 | $ | 73.00 | |||||
| Net NGL production per day (MBbl/d) | 10 | 10 | |||||||
| Realized NGL price ($ per Bbl) | $ | 54.64 | $ | 52.62 | |||||
| Net natural gas production per day (Mmcf/d) | 117 | 115 | |||||||
| Realized natural gas price with derivative settlements ($ per Mcf) | $ | 4.12 | $ | 3.65 | |||||
| Net total production per day (MBoe/d) | 141 | 141 | |||||||
| Margin from purchased commodities4($ millions) | $ | 14 | $ | 6 | |||||
| Electricity margin5($ millions) | $ | 12 | $ | 30 | |||||
| Net gain from commodity derivatives ($ millions) | $ | 6 | $ | (49 | ) | ||||
| Other revenue and operating expenses, net6($ millions) | $ | (27 | ) | $ | (50 | ) | |||
| Selected Financial Statement Data and non-GAAP measures: | 1st Quarter | 4th Quarter | |||||||
| ($ and shares in millions, except per share amounts) | 2025 | 2024 | |||||||
| Statements of Operations: | |||||||||
| Revenues | |||||||||
| Total operating revenues | $ | 912 | $ | 877 | |||||
| Selected Expenses | |||||||||
| Operating costs | $ | 316 | $ | 323 | |||||
| General and administrative expenses | $ | 72 | $ | 95 | |||||
| Adjusted general and administrative expenses1 | $ | 66 | $ | 85 | |||||
| Taxes other than on income | $ | 70 | $ | 80 | |||||
| Transportation costs | $ | 20 | $ | 21 | |||||
| Operating Income | $ | 186 | $ | 68 | |||||
| Interest and debt expense | $ | (27 | ) | $ | (28 | ) | |||
| Income tax (provision) benefit | $ | (47 | ) | $ | (8 | ) | |||
| Net income | $ | 115 | $ | 33 | |||||
| EPS, Non-GAAP Measures and Select Balance Sheet Data | |||||||||
| Adjusted net income1 | $ | 98 | $ | 84 | |||||
| Weighted-average common shares outstanding – diluted | 91.2 | 92.2 | |||||||
| Net income per share – diluted | $ | 1.26 | $ | 0.36 | |||||
| Adjusted net income per share1– diluted | $ | 1.07 | $ | 0.91 | |||||
| Adjusted EBITDAX1 | $ | 328 | $ | 316 | |||||
| Deferred income tax provision (benefit) | $ | 35 | $ | (9 | ) | ||||
| Net cash provided by operating activities | $ | 186 | $ | 206 | |||||
| Net cash provided by operating activities before net changes in operating assets and liabilities1 | $ | 252 | $ | 258 | |||||
| Capital investments | $ | 55 | $ | 88 | |||||
| Free cash flow1 | $ | 131 | $ | 118 | |||||
| Cash and cash equivalents | $ | 214 | $ | 372 | |||||
Guidance
The following table provides key second quarter and full year 2025 financial and operating guidance. With respect to oil and gas development, CRC will run a one rig program in the first half of 2025 and expects to run a two rig program in the second half of 2025 using existing permits in hand. CRC currently holds sufficient permits to maintain its existing capital program through 2025. See Attachment 2 for additional information on CRC’s second quarter and full year 2025 guidance.
| CRC Guidance7 | 2Q25E | Total Year 2025E |
| Net Production (MBoe/d) | 133 – 137 | 132 – 138 |
| Net Oil Production (%) | ~79% | ~79% |
| Capital ($ millions) | $81 – $92 | $285 – $335 |
| Adjusted EBITDAX1 ($ millions) | $275 – $290 | $1,100 – $1,200 |
Shareholder Returns and Dividend Announcements
CRC is committed to returning cash to shareholders through dividends and repurchases of its outstanding common stock. During the first quarter of 2025, CRC repurchased 2.3 million shares for $100 million at an average price of $44 per share2.
Since mid-2021, the Company has returned approximately $1,195 million to shareholders2, including $893 million in share repurchases and $302 million in dividends. As of March 31, 2025, CRC had approximately $457 million remaining for repurchases under its authorized share repurchase program.
On May 5, 2025, CRC’s Board of Directors declared a quarterly cash dividend2 of $0.3875 per share of common stock, payable to shareholders of record on May 30, 2025. The dividend is expected to be paid on June 13, 2025.
Balance Sheet and Liquidity
In February 2025, CRC redeemed $123 million of its 2026 Senior Notes at 100% of the principal amount of such notes. CRC expects to redeem the remaining $122 million principal amount in 2025.
As of March 31, 2025, CRC had $199 million in available cash and cash equivalents3, $983 million of available borrowing capacity under its Facility (which reflects $1,150 million of borrowing capacity less $167 million of outstanding letters of credit) and liquidity1, 3 of $1,182 million.
In April 2025, CRC’s borrowing base was reaffirmed under its Revolving Credit Facility at $1,500 million.
Upcoming Investor Conference Participation
CRC will be participating in the following events In May through July 2025:
- UBS Energy Transition and Decarbonization Conference on May 13 to 14 in New York, NY
- Morgan Stanley Sustainability Leadership Summit on May 15 in New York, NY
- Goldman Sachs Leveraged Finance and Credit Conference on May 28 to 29 in Dana Point, CA
- RBC Capital Markets Global Energy, Power & Infrastructure Conference on June 3 in New York, NY
- BofA Energy and Power Credit Conference on June 3 in New York, NY
- Jefferies Energy Conference on June 11 in Kiawah, SC
- J.P. Morgan Energy, Power, Renewables, and Mining Conference on June 24 in New York, NY
- RBC Energy Transition Conference on June 26 in London, UK
- TD Energy, Power & Utilities Conference on July 8 to 9 in Calgary, AB, Canada
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 and webcast is planned for 1 p.m. ET (10 a.m. PT) on Wednesday, May 7, 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/10197788/feb45747fc. A digital replay of the conference call will be available for approximately 90 days.
1 See Attachment 3 for the non-GAAP financial measures of operating costs per BOE, adjusted net income (loss), adjusted net income (loss) per share – basic and diluted, net cash provided by operating activities before net changes in operating assets and liabilities, adjusted EBITDAX, free cash flow and adjusted general and administrative expenses including reconciliations to their most directly comparable GAAP measure, where applicable. See Attachment 2 for the 2Q25 and 2025 estimates of the non-GAAP measures of adjusted EBITDAX and adjusted general and administrative expenses, including reconciliations to its most directly comparable GAAP measure.
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 approximately $1 million in both the three months ended March 31, 2025 and 2024 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented.
3 Excludes restricted cash of $15 million.
4 Margin from purchased commodities is calculated as the difference between revenue from purchased commodities and costs related to purchased commodities, and excludes costs of transportation.
5 Electricity margin is calculated as the difference between electricity sales and electricity generation expenses.
6 Other operating revenue and expenses, net is calculated as the difference between other revenue and other operating expenses, net. Includes exploration expense and CMB expenses. CMB expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.
7 2Q25E guidance assumes Brent price of $63.00 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $4.11 per mcf. Total year 2025E guidance assumes Brent price of $63.00 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $4.28 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 that if developed will inject CO2 captured from industrial sources into depleted reservoirs deep underground for permanent sequestration. For more information, visit 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. These 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 are described in its most recent Annual Report on Form 10-K and its other periodic filings with the Securities and Exchange Commission. These factors include, but are not limited to: fluctuations in commodity prices; production levels and/or pricing by OPEC or U.S. producers; government policy, war and political conditions and events; integration efforts and projected benefits in connection with the Aera Merger and other acquisitions, divestitures and joint ventures; regulatory actions and changes that affect the oil and gas industry generally and us in particular; the efforts of activists to delay 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 and other renewable energy efforts; future dividends and share repurchases an 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 filing date, and CRC 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 | |||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | |||||||||
| ($ and shares in millions, except per share amounts) | 2025 | 2024 | 2024 | ||||||||
| Statements of Operations: | |||||||||||
| Revenues | |||||||||||
| Oil, natural gas and NGL sales | $ | 814 | $ | 826 | $ | 429 | |||||
| Net gain (loss) from commodity derivatives | 6 | (49 | ) | (71 | ) | ||||||
| Revenue from marketing of purchased commodities | 64 | 59 | 74 | ||||||||
| Electricity sales | 22 | 39 | 15 | ||||||||
| Interest and other revenue | 6 | 2 | 7 | ||||||||
| Total operating revenues | 912 | 877 | 454 | ||||||||
| Operating Expenses | |||||||||||
| Operating costs | 316 | 323 | 176 | ||||||||
| General and administrative expenses | 72 | 95 | 57 | ||||||||
| Depreciation, depletion and amortization | 131 | 142 | 53 | ||||||||
| Taxes other than on income | 70 | 80 | 38 | ||||||||
| Costs related to marketing of purchased commodities | 50 | 53 | 54 | ||||||||
| Electricity generation expenses | 10 | 9 | 8 | ||||||||
| Transportation costs | 20 | 21 | 20 | ||||||||
| Accretion expense | 29 | 31 | 12 | ||||||||
| Net (gain) loss on natural gas purchase derivatives | (6 | ) | 19 | 1 | |||||||
| Measurement period adjustments | 1 | (12 | ) | — | |||||||
| Other operating expenses, net | 33 | 52 | 45 | ||||||||
| Total operating expenses | 726 | 813 | 464 | ||||||||
| Net gain on asset divestitures | — | 4 | 6 | ||||||||
| Operating Income | 186 | 68 | (4 | ) | |||||||
| Non-Operating (Expenses) Income | |||||||||||
| Interest and debt expense | (27 | ) | (28 | ) | (13 | ) | |||||
| Loss from investment in unconsolidated subsidiaries | (1 | ) | (1 | ) | (3 | ) | |||||
| Loss on early extinguishment of debt | (1 | ) | — | — | |||||||
| Other non-operating income (loss), net | 5 | 2 | 1 | ||||||||
| Income Before Income Taxes | 162 | 41 | (19 | ) | |||||||
| Income tax (provision) | (47 | ) | (8 | ) | 9 | ||||||
| Net Income | $ | 115 | $ | 33 | $ | (10 | ) | ||||
| Net income per share – basic | $ | 1.27 | $ | 0.36 | $ | (0.14 | ) | ||||
| Net income per share – diluted | $ | 1.26 | $ | 0.36 | $ | (0.14 | ) | ||||
| Adjusted net income | $ | 98 | $ | 84 | $ | 54 | |||||
| Adjusted net income per share – basic | $ | 1.08 | $ | 0.93 | $ | 0.78 | |||||
| Adjusted net income per share – diluted | $ | 1.07 | $ | 0.91 | $ | 0.75 | |||||
| Weighted-average common shares outstanding – basic | 90.6 | 90.8 | 69.0 | ||||||||
| Weighted-average common shares outstanding – diluted | 91.2 | 92.2 | 69.0 | ||||||||
| Adjusted EBITDAX | $ | 328 | $ | 316 | $ | 149 | |||||
| Effective tax rate | 29 | % | 20 | % | 45 | % | |||||
| 1st Quarter | 4th Quarter | 1st Quarter | |||||||||
| ($ in millions) | 2025 | 2024 | 2024 | ||||||||
| Cash Flow Data: | |||||||||||
| Net cash provided by operating activities | $ | 186 | $ | 206 | $ | 87 | |||||
| Net cash used in investing activities | $ | (79 | ) | $ | (67 | ) | $ | (49 | ) | ||
| Net cash (used in) provided by financing activities | $ | (265 | ) | $ | (8 | ) | $ | (131 | ) | ||
| March 31, | December 31, | ||||||||||
| ($ in millions) | 2024 | 2024 | |||||||||
| Selected Balance Sheet Data: | |||||||||||
| Total current assets | $ | 799 | $ | 1,024 | |||||||
| Property, plant and equipment, net | $ | 5,618 | $ | 5,680 | |||||||
| Deferred tax asset | $ | 60 | $ | 73 | |||||||
| Total current liabilities | $ | 961 | $ | 980 | |||||||
| Long-term debt, net | $ | 888 | $ | 1,132 | |||||||
| Noncurrent asset retirement obligations | $ | 989 | $ | 995 | |||||||
| Deferred tax liability | $ | 134 | $ | 113 | |||||||
| Total stockholders’ equity | $ | 3,516 | $ | 3,538 | |||||||
| GAINS AND LOSSES FROM COMMODITY DERIVATIVES | |||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | |||||||||
| ($ millions) | 2025 | 2024 | 2024 | ||||||||
| Non-cash derivative gain (loss) | $ | 22 | $ | 51 | $ | (59 | ) | ||||
| Net received (paid) on settled commodity derivatives | (16 | ) | (2 | ) | (12 | ) | |||||
| Net gain (loss) from commodity derivatives | $ | 6 | $ | 49 | $ | (71 | ) | ||||
| CAPITAL INVESTMENTS | ||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||
| ($ millions) | 2025 | 2024 | 2024 | |||||
| Facilities | $ | 8 | $ | 44 | $ | 14 | ||
| Drilling and completions | 15 | 17 | 15 | |||||
| Workovers | 19 | 17 | 7 | |||||
| Total oil and natural gas capital | 42 | 78 | 36 | |||||
| Carbon management | 2 | 6 | 4 | |||||
| Corporate and other | 11 | 4 | 14 | |||||
| Total capital program | $ | 55 | $ | 88 | $ | 54 | ||
| Attachment 2 | |||||||
| CRC GUIDANCE | Consolidated 2Q25E | Oil and Natural Gas 2Q25E | Carbon Management 2Q25E | ||||
| Net Production (MBoe/d) | 133 – 137 | ||||||
| Net Oil Production (%) | ~79% | ||||||
| Operating Costs ($ millions) | $295 – $315 | $295 – $315 | |||||
| Non-Energy Operating and Gas Processing Costs ($ millions) | $215 – $230 | ||||||
| General and Administrative Expenses ($ millions) | $76 – $80 | $10 – $14 | $2 – $4 | ||||
| Adjusted General and Administrative Expenses ($ millions) | $69 – $74 | $10 – $14 | $2 – $4 | ||||
| Depreciation, Depletion and Amortization ($ millions) | $124 – $128 | $113 – $119 | |||||
| Capital ($ millions) | $81 – $92 | $71 – $75 | $5 – $10 | ||||
| Drilling, Completions and Workovers ($ millions) | $42 – $44 | $42 – $44 | |||||
| Facilities ($ millions) | $29 – $31 | $29 – $31 | |||||
| Carbon Management Business ($ millions) | $5 – $10 | $5 – $10 | |||||
| Corporate and Other ($ millions) | $5 – $7 | ||||||
| Adjusted EBITDAX ($ millions) | $275 – $290 | $290 – $320 | ($15) – ($20) | ||||
| Margin from Purchased Commodities ($ millions)(1) | $20 – $25 | ||||||
| Electricity Margin ($ millions)(2) | $40 – $45 | ||||||
| Other Operating Revenue and Expenses, net ($ millions)(3) | $5 – $20 | $10 – $15 | |||||
| Transportation Costs ($ millions) | $22 – $26 | $6 – $10 | |||||
| Taxes Other Than on Income ($ millions) | $60 – $65 | $50 – $55 | |||||
| Interest and Debt Expense ($ millions) | $26 – $30 | ||||||
| Other Assumptions: | |||||||
| Brent ($/Bbl) | $63.00 | ||||||
| NYMEX ($/Mcf) | $4.11 | ||||||
| Oil – % of Brent: | 96% to 100% | ||||||
| NGL – % of Brent: | 55% to 60% | ||||||
| Natural Gas – % of NYMEX: | 50% to 60% | ||||||
| Deferred Income Taxes | (68%) – (72%) | ||||||
| Effective Tax Rate | 29% | ||||||
| CRC GUIDANCE | Consolidated 2025E | Oil and Natural Gas 2025E | Carbon Management 2025E | ||||
| Net Production (MBoe/d) | 132 – 138 | ||||||
| Net Oil Production (%) | ~79% | ||||||
| Operating Costs ($ millions) | $1,230 – $1,300 | $1,230 – $1,300 | |||||
| Non-Energy Operating and Gas Processing Costs ($ millions) | $850 – $890 | ||||||
| General and Administrative Expenses ($ millions) | $310 – $335 | $40 – $50 | $10 – $15 | ||||
| Adjusted General and Administrative Expenses ($ millions) | $289 – $309 | $40 – $50 | $10 – $15 | ||||
| Depreciation, Depletion and Amortization ($ millions) | $500 – $515 | $465 – $480 | |||||
| Capital ($ millions) | $285 – $335 | $250 – $280 | $20 – $30 | ||||
| Drilling, Completions and Workovers ($ millions) | $165 – $180 | $165 – $180 | |||||
| Facilities ($ millions) | $85 – $100 | $85 – $100 | |||||
| Carbon Management Business ($ millions) | $20 – $30 | $20 – $30 | |||||
| Corporate and Other ($ millions) | $15 – $25 | ||||||
| Adjusted EBITDAX ($ millions) | $1,100 – $1,200 | $1,205 – $1,340 | ($80) – ($85) | ||||
| Margin from Purchased Commodities ($ millions)(1) | $80 – $95 | ||||||
| Electricity Margin ($ millions)(2) | $175 – $190 | ||||||
| Other Operating Revenue and Expenses, net ($ millions)(3) | $35 – $85 | $60 – $90 | |||||
| Transportation Costs ($ millions) | $90 – $98 | $28 – $32 | |||||
| Taxes Other Than on Income ($ millions) | $265 – $285 | $220 – $230 | |||||
| Interest and Debt Expense ($ millions) | $100 – $113 | ||||||
| Commodity Assumptions: | |||||||
| Brent ($/Bbl) | $63.00 | ||||||
| NYMEX ($/Mcf) | $4.28 | ||||||
| Oil – % of Brent: | 96% to 100% | ||||||
| NGL – % of Brent: | 60% to 68% | ||||||
| Natural Gas – % of NYMEX: | 80% to 90% | ||||||
| Deferred Income Taxes | 5% – 10% | ||||||
| Effective Tax Rate | 29% | ||||||
(1) Margin from purchased commodities is calculated as the difference between revenue from marketing of purchased commodities and costs related to marketing of purchased commodities, and excludes costs of transportation.
(2) Electricity margin is calculated as the difference between electricity sales and electricity generation expenses.
(3) Other operating revenue and expenses, net is calculated as the difference between other revenue and other operating expenses, net and includes exploration expense and CMB expenses. CMB expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.
See Attachment 3 for management’s disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC’s results of operations and financial condition.
ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES RECONCILIATION
| 2Q25E | |||||||||||||||||||
| Consolidated | Oil and Natural Gas | Carbon Management | |||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||
| General and administrative expenses | $ | 76 | $ | 80 | $ | 10 | $ | 14 | $ | 2 | $ | 4 | |||||||
| Equity-settled stock-based compensation | (6 | ) | (6 | ) | — | — | — | — | |||||||||||
| Other | (1 | ) | (1 | ) | — | — | — | — | |||||||||||
| Estimated adjusted general and administrative expenses | $ | 69 | $ | 74 | $ | 10 | $ | 14 | $ | 2 | $ | 4 | |||||||
| Total Year 2025E | |||||||||||||||||||
| Consolidated | Oil and Natural Gas | Carbon Management | |||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||
| General and administrative expenses | $ | 310 | $ | 335 | $ | 40 | $ | 50 | $ | 10 | $ | 15 | |||||||
| Equity-settled stock-based compensation | (19 | ) | (24 | ) | — | — | — | — | |||||||||||
| Other | (2 | ) | (2 | ) | — | — | — | — | |||||||||||
| Estimated adjusted general and administrative expenses | $ | 289 | $ | 309 | $ | 40 | $ | 50 | $ | 10 | $ | 15 | |||||||
ESTIMATED ADJUSTED EBITDAX RECONCILIATION
| Consolidated | ||||||||||||||||||||
| 2Q25E | 2025E | |||||||||||||||||||
| ($ millions) | Low | High | Low | High | ||||||||||||||||
| Net income | $ | 77 | $ | 92 | $ | 278 | $ | 292 | ||||||||||||
| Interest and debt expense, net | 26 | 30 | 100 | 113 | ||||||||||||||||
| Depreciation, depletion and amortization | 124 | 128 | 500 | 515 | ||||||||||||||||
| Income taxes | 20 | 22 | 98 | 102 | ||||||||||||||||
| Unusual, infrequent and other items | (8 | ) | (14 | ) | (15 | ) | 30 | |||||||||||||
| Other non-cash items | ||||||||||||||||||||
| Accretion expense | 30 | 31 | 120 | 124 | ||||||||||||||||
| Stock-settled compensation | 6 | 6 | 19 | 24 | ||||||||||||||||
| Estimated adjusted EBITDAX | $ | 275 | $ | 295 | $ | 1,100 | $ | 1,200 | ||||||||||||
| Net cash provided by operating activities | $ | 115 | $ | 130 | $ | 752 | $ | 772 | ||||||||||||
| Cash interest | 8 | 14 | 94 | 100 | ||||||||||||||||
| Cash income taxes | 35 | 37 | 90 | 94 | ||||||||||||||||
| Working capital changes | 117 | 114 | 164 | 234 | ||||||||||||||||
| Estimated adjusted EBITDAX | $ | 275 | $ | 295 | $ | 1,100 | $ | 1,200 | ||||||||||||
| Oil and Natural Gas1 | ||||||||||||||||||||
| 2Q25E | 2025E | |||||||||||||||||||
| ($ millions) | Low | High | Low | High | ||||||||||||||||
| Segment profit | $ | 155 | $ | 165 | $ | 660 | $ | 760 | ||||||||||||
| Depreciation, depletion and amortization | 113 | 119 | 465 | 480 | ||||||||||||||||
| Unusual, infrequent and other items | (3 | ) | 6 | (30 | ) | (20 | ) | |||||||||||||
| Other non-cash items | ||||||||||||||||||||
| Accretion expense | 25 | 30 | 110 | 120 | ||||||||||||||||
| Estimated adjusted EBITDAX | $ | 290 | $ | 320 | $ | 1,205 | $ | 1,340 | ||||||||||||
| Carbon Management1 | |||||||||||||||||||||
| 2Q25E | 2025E | ||||||||||||||||||||
| ($ millions) | Low | High | Low | High | |||||||||||||||||
| Segment loss | $ | (17 | ) | $ | (28 | ) | $ | (90 | ) | $ | (110 | ) | |||||||||
| Interest and debt expense, net | 1 | 5 | 5 | 14 | |||||||||||||||||
| Loss from investment on unconsolidated subsidiary | 1 | 3 | 5 | 11 | |||||||||||||||||
| Other non-cash items | |||||||||||||||||||||
| Stock-settled compensation | — | — | — | — | |||||||||||||||||
| Estimated adjusted EBITDAX | $ | (15 | ) | $ | (20 | ) | $ | (80 | ) | $ | (85 | ) | |||||||||
| (1) 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. | |||||||||||||||||||||
| 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, adjusted EBITDAX for the oil and natural gas segment, adjusted EBITDAX for the carbon management business, net cash provided by operating activities before net changes in operating assets and liabilities, free cash flow, adjusted general and administrative expenses, and operating costs 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 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. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions, except per share amounts) | 2025 | 2024 | 2024 | |||||||||
| Net income | $ | 115 | $ | 33 | $ | (10 | ) | |||||
| Unusual, infrequent and other items: | ||||||||||||
| Non-cash derivative loss (gain) | (22 | ) | 51 | 59 | ||||||||
| Asset impairment | — | 1 | — | |||||||||
| Severance and termination costs | 2 | 2 | — | |||||||||
| Aera merger related costs | 3 | 1 | 13 | |||||||||
| Increased power and fuel costs due to power plant maintenance | — | 6 | 21 | |||||||||
| Net gain on asset divestitures | — | (4 | ) | (6 | ) | |||||||
| Loss on early extinguishment of debt | 1 | — | — | |||||||||
| Measurement period adjustments | 1 | — | — | |||||||||
| Other, net | (9 | ) | 13 | 2 | ||||||||
| Total unusual, infrequent and other items | (24 | ) | 70 | 89 | ||||||||
| Income tax (benefit) provision of adjustments at effective tax rate | 7 | (19 | ) | (25 | ) | |||||||
| Income tax benefit – out of period | — | — | — | |||||||||
| Adjusted net income | $ | 98 | $ | 84 | $ | 54 | ||||||
| Net income per share – basic | $ | 1.27 | $ | 0.36 | $ | (0.14 | ) | |||||
| Net income per share – diluted | $ | 1.26 | $ | 0.36 | $ | (0.14 | ) | |||||
| Adjusted net income per share – basic | $ | 1.08 | $ | 0.93 | $ | 0.78 | ||||||
| Adjusted net income per share – diluted | $ | 1.07 | $ | 0.91 | $ | 0.75 | ||||||
| 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 oil and gas segment (E&P adjusted EBITDAX) and its carbon management segment (CMB adjusted EBITDAX). Management believes these supplemental measures are useful for investors to understand the results of the core oil and gas business and its investment in developing the carbon management business. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions, except per BOE amounts) | 2025 | 2024 | 2024 | |||||||||
| Net income | $ | 115 | $ | 33 | $ | (10 | ) | |||||
| Interest and debt expense | 27 | 28 | 13 | |||||||||
| Depreciation, depletion and amortization | 131 | 142 | 53 | |||||||||
| Income tax provision | 47 | 8 | (9 | ) | ||||||||
| Exploration expense | — | — | 1 | |||||||||
| Interest income | (3 | ) | (4 | ) | (6 | ) | ||||||
| Loss from investment in unconsolidated subsidiaries | 1 | — | — | |||||||||
| Unusual, infrequent and other items(1) | (24 | ) | 70 | 89 | ||||||||
| Non-cash items | ||||||||||||
| Accretion expense | 29 | 31 | 12 | |||||||||
| Stock-based compensation | 6 | 6 | 5 | |||||||||
| Taxes related to acquisition accounting and other | — | 2 | — | |||||||||
| Pension and post-retirement benefits | (1 | ) | — | 1 | ||||||||
| Adjusted EBITDAX | $ | 328 | $ | 316 | $ | 149 | ||||||
| Net cash provided by operating activities | $ | 186 | $ | 206 | $ | 87 | ||||||
| Cash interest payments | 11 | 42 | 21 | |||||||||
| Cash interest received | (3 | ) | (4 | ) | (6 | ) | ||||||
| Cash income taxes | — | 50 | 22 | |||||||||
| Exploration expenditures | — | — | 1 | |||||||||
| Adjustments to working capital changes | 134 | 22 | 24 | |||||||||
| Adjusted EBITDAX | $ | 328 | $ | 316 | $ | 149 | ||||||
| Adjusted EBITDAX per Boe | $ | 25.92 | $ | 24.35 | $ | 21.47 | ||||||
| (1) See Adjusted Net Income (Loss) reconciliation. | ||||||||||||
| SEGMENT ADJUSTED EBITDAX | ||||||||||||
| CRC defines segments 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 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. | ||||||||||||
| Oil & Natural Gas Segment2 | 1st Quarter | 4th Quarter | 1st Quarter | |||||||||
| ($ millions, except per BOE amounts) | 2025 | 2024(1) | 2024 | |||||||||
| Segment profit | $ | 266 | $ | 268 | $ | 132 | ||||||
| Depreciation, depletion and amortization | 126 | 129 | 49 | |||||||||
| Exploration expense | — | — | 1 | |||||||||
| Accretion expense | 29 | 31 | 12 | |||||||||
| Adjusted income items | 1 | (3 | ) | 14 | ||||||||
| Adjusted EBITDAX – Oil and Natural Gas | $ | 422 | $ | 425 | $ | 208 | ||||||
| Carbon Management Segment2 | ||||||||||||
| Segment loss | $ | (25 | ) | $ | (31 | ) | $ | (14 | ) | |||
| Interest on contingent liability (related to Carbon TerraVault JV) | 3 | 3 | 1 | |||||||||
| Loss from investment in unconsolidated subsidiaries | 1 | 2 | — | |||||||||
| Adjusted income items | — | 1 | — | |||||||||
| Adjusted EBITDAX – Carbon Management | $ | (21 | ) | $ | (25 | ) | $ | (13 | ) | |||
| (1) Certain amounts related to the fourth quarter of 2024 previously reported in the company’s Q4 2024 earnings release have been corrected. These corrections related to segment classification errors and have no material impact on the company’s overall financial position. (2) 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. | ||||||||||||
| 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. CRC supplemented its non-GAAP measure of free cash flow with net cash provided by operating activities before net changes in operating assets and liabilities, which it believes is a useful measure for investors to understand the predictability of CRC’s cash flow by removing fluctuations related to the timing of payments between periods. CRC defines adjusted free cash flow after special items as free cash flow before transaction and integration costs from the Aera Merger. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions) | 2025 | 2024 | 2024 | |||||||||
| Net cash provided by operating activities before net changes in operating assets and liabilities | $ | 252 | $ | 258 | $ | 92 | ||||||
| Net changes in operating assets and liabilities | (66 | ) | (52 | ) | (5 | ) | ||||||
| Net cash provided by operating activities | 186 | 206 | 87 | |||||||||
| Capital investments | (55 | ) | (88 | ) | (54 | ) | ||||||
| Free cash flow | $ | 131 | $ | 118 | $ | 33 | ||||||
| Add: Aera merger related costs | 3 | 1 | 13 | |||||||||
| Free cash flow after special items | $ | 134 | $ | 119 | $ | 46 | ||||||
| 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. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions) | 2025 | 2024 | 2024 | |||||||||
| General and administrative expenses | $ | 72 | $ | 95 | $ | 57 | ||||||
| Stock-based compensation | (6 | ) | (6 | ) | (5 | ) | ||||||
| Accelerated vesting | — | (3 | ) | — | ||||||||
| Other | — | (1 | ) | (1 | ) | |||||||
| Adjusted G&A expenses | $ | 66 | $ | 85 | $ | 51 | ||||||
| Adjusted G&A per BOE | $ | 5.22 | $ | 6.55 | $ | 7.35 | ||||||
| OPERATING COSTS PER BOE, EXCLUDING EFFECTS OF PSCs | ||||||||||||
| 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. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ per BOE) | 2025 | 2024 | 2024 | |||||||||
| Energy operating costs(1) | $ | 8.76 | $ | 7.70 | $ | 8.07 | ||||||
| Gas processing costs(2) | 0.32 | 0.31 | 0.58 | |||||||||
| Non-energy operating costs(3) | 16.52 | 17.34 | 17.15 | |||||||||
| Operating costs | $ | 25.60 | $ | 25.35 | $ | 25.80 | ||||||
| Operating costs, after hedges | $ | 26.55 | $ | 26.40 | $ | 26.09 | ||||||
| (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. | ||||||||||||
| (3)Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. | ||||||||||||
| Attachment 4 | ||||||
| PRODUCTION STATISTICS | ||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||
| Net Production Per Day | 2025 | 2024 | 2024 | |||
| Oil (MBbl/d) | ||||||
| San Joaquin Basin | 84 | 86 | 30 | |||
| Los Angeles Basin | 18 | 17 | 18 | |||
| Other Basins | 9 | 9 | — | |||
| Total | 111 | 112 | 48 | |||
| NGLs (MBbl/d) | ||||||
| San Joaquin Basin | 10 | 10 | 11 | |||
| Total | 10 | 10 | 11 | |||
| Natural Gas (MMcf/d) | ||||||
| San Joaquin Basin | 101 | 98 | 90 | |||
| Los Angeles Basin | 1 | 1 | 1 | |||
| Sacramento Basin | 12 | 13 | — | |||
| Other Basins | 3 | 3 | 14 | |||
| Total | 117 | 115 | 105 | |||
| Total Net Production (MBoe/d) | 141 | 141 | 76 | |||
| Gross Operated and Net Non-Operated | 1st Quarter | 4th Quarter | 1st Quarter | |||
| Production Per Day | 2025 | 2024 | 2024 | |||
| Oil (MBbl/d) | ||||||
| San Joaquin Basin | 90 | 93 | 34 | |||
| Los Angeles Basin | 22 | 23 | 24 | |||
| Other Basins | 11 | 11 | — | |||
| Total | 123 | 127 | 58 | |||
| NGLs (MBbl/d) | ||||||
| San Joaquin Basin | 10 | 10 | 11 | |||
| Other Basins | — | 1 | — | |||
| Total | 10 | 11 | 11 | |||
| Natural Gas (MMcf/d) | ||||||
| San Joaquin Basin | 134 | 135 | 128 | |||
| Los Angeles Basin | 7 | 6 | 7 | |||
| Sacramento Basin | 15 | 17 | 17 | |||
| Other Basins | 3 | 3 | — | |||
| Total | 159 | 161 | 152 | |||
| Total Gross Production (MBoe/d) | 160 | 165 | 94 | |||
| Attachment 5 | |||||||||||
| PRICE STATISTICS | |||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | |||||||||
| 2025 | 2024 | 2024 | |||||||||
| Oil ($ per Bbl) | |||||||||||
| Realized price with derivative settlements | $ | 72.01 | $ | 73.00 | $ | 77.17 | |||||
| Realized price without derivative settlements | $ | 73.57 | $ | 72.82 | $ | 80.16 | |||||
| NGLs ($/Bbl) | $ | 54.64 | $ | 52.62 | $ | 50.50 | |||||
| Natural gas ($/Mcf) | |||||||||||
| Realized price with derivative settlements | $ | 4.12 | $ | 3.65 | $ | 3.90 | |||||
| Realized price without derivative settlements | $ | 4.12 | $ | 3.65 | $ | 3.90 | |||||
| Index Prices | |||||||||||
| Brent oil ($/Bbl) | $ | 74.92 | $ | 73.97 | $ | 81.84 | |||||
| WTI oil ($/Bbl) | $ | 71.42 | $ | 70.27 | $ | 76.96 | |||||
| NYMEX average monthly settled price ($/MMBtu) | $ | 3.65 | $ | 2.79 | $ | 2.24 | |||||
| Realized Prices as Percentage of Index Prices | |||||||||||
| Oil with derivative settlements as a percentage of Brent | 96 | % | 99 | % | 94 | % | |||||
| Oil without derivative settlements as a percentage of Brent | 98 | % | 98 | % | 98 | % | |||||
| Oil with derivative settlements as a percentage of WTI | 101 | % | 104 | % | 100 | % | |||||
| Oil without derivative settlements as a percentage of WTI | 103 | % | 104 | % | 104 | % | |||||
| NGLs as a percentage of Brent | 73 | % | 71 | % | 62 | % | |||||
| NGLs as a percentage of WTI | 77 | % | 75 | % | 66 | % | |||||
| Natural gas with derivative settlements as a percentage of NYMEX contract month average | 113 | % | 131 | % | 174 | % | |||||
| Natural gas without derivative settlements as a percentage of NYMEX contract month average | 113 | % | 131 | % | 174 | % | |||||
| Attachment 6 | |||||||||
| FIRST QUARTER 2025 DRILLING ACTIVITY | |||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | ||||
| Development Wells | |||||||||
| Primary | 3 | — | — | — | 3 | ||||
| Waterflood | — | — | — | — | — | ||||
| Steamflood | — | — | — | — | — | ||||
| Total(1) | 3 | — | — | — | 3 | ||||
| (1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | |||||||||
This press release was published by a CLEAR® Verified individual.
