California Resources Corporation Reports Fourth Quarter and Full-Year 2025 Financial and Operating Results; Announces 2026 Guidance
25% Year-Over-Year Production Growth and Highest Annual Free Cash Flow Since 2021
Receipt of New Drilling Permits Supports Planned 2026 Drilling Program
LONG BEACH, Calif., March 02, 2026 (GLOBE NEWSWIRE) -- California Resources Corporation (NYSE: CRC) (CRC) today reported its financial and operating results for the fourth quarter and full-year 2025. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Monday, March 2, 2026. Conference call details can be found within this release.
Fourth Quarter Highlights
- Reported net income of $12 million, adjusted net income1 of $40 million and $251 million of adjusted EBITDAX1
- Generated net cash provided by operating activities of $235 million and $115 million of free cash flow1
- Delivered an average of 137 thousand barrels of oil equivalent per day5 (MBoe/d) (80% oil); invested total capital of $120 million including drilling, completions and workover capital1 of $56 million
- Increased annual dividend by 5%; marking four consecutive years of dividend growth2
- Returned $59 million to shareholders including $34 million in dividends and $25 million in share repurchases2
- Closed all-stock combination with Berry Corporation on December 18, 2025
- Announced a new memorandum of understanding (MOU)4 with a leading California power producer to provide CO2 transportation and storage and explore decarbonized power solutions near Silicon Valley. See California Resources Corporation and Middle River Power to Advance Decarbonized Power Solutions in California for additional information
2025 Highlights
- Increased average net production by 25% year-over-year to 138 MBoe/d5 (79% oil), and realized $235 million in Aera merger-related synergies
- Reported net income of $363 million, adjusted net income¹ of $359 million and highest annual adjusted EBITDAX¹ of $1,241 million since 2021
- Generated $865 million of net cash provided by operating activities and free cash flow¹ of $543 million, highest annual free cash flow since 2021
- Returned $513 million to shareholders including $377 million in share repurchases and $136 million in dividends2
- Lowered base decline to 8%–13% from 10%–15% through improved reservoir management
- Increased proved undeveloped reserves by 190% and total proved reserves by 20% through operational improvements and mergers, despite 14% year-over-year decline in SEC pricing for oil
- Exited 2025 with $117 million in available cash3, $1,284 million in available borrowing capacity and liquidity of $1,401 million
- Increased aggregate elected commitment under the Revolving Credit Facility to $1,460 million in 2025 from $1,150 million
- Received “Grade A” certifications under MiQ’s Methane Emissions Performance Standard for production assets across the Los Angeles, Ventura, and San Joaquin basins (excluding assets added in the Berry Merger)
- Substantially completed construction of CRC's first carbon capture and storage (CCS) project at the Elk Hills cryogenic gas plant
- Executed new MOUs4 with leading California industrial and power partners to evaluate decarbonized solutions. See Carbon TerraVault's 2025 Press Release for additional information
2026 Outlook
- CRC is receiving new drilling permits and currently holds the majority of permits necessary to undertake its 2026 capital program
- Targeting approximately 12% year-over-year production growth, averaging 152–157 MBoe/d (~81% oil), supported by four operated drilling rigs
- Capital investments expected to range between $430–$470 million, including $280–$300 million for drilling, completions, and workovers1, and $12–$20 million for carbon management initiatives
- Expect to realize $80–$90 million of Berry merger-related synergies within 12 months of closing, including $35 to $40 million in general and administrative expenses, $25 to $30 million in operating costs and $20 million in financing costs
- Targeting first CO₂ injection at its CCS project at the Elk Hills cryogenic gas plant in spring 2026, subject to commissioning and final regulatory approval. See Carbon TerraVault's 2025 Press Release for additional information
“CRC delivered a landmark year in 2025, driven by strong financial performance, robust cash flow generation, and disciplined execution, while returning substantial cash to shareholders,” said Francisco Leon, CRC’s President and Chief Executive Officer. “Our teams made meaningful progress improving reservoir management across our high-quality, low-decline conventional asset base and advancing several strategic initiatives that strengthen the company’s long-term foundation.
"Our 2026 priorities are clear: safely and efficiently operate our core businesses, deliver on the synergies from the Berry merger, and continue to advance high-return opportunities across our portfolio while maintaining financial discipline. With a resilient asset base and a strong hedge position, CRC is well positioned to manage near-term volatility and generate strong cash flows from which to enhance shareholder returns.”
Fourth Quarter and Total Year 2025 Results
| Select Production, Price and Financial Results and Non-GAAP Measures | 4th Quarter | 3rd Quarter | Total Year | Total Year | |||||||||||
| ($ in millions except production and prices) | 2025 | 2025 | 2025 | 2024 | |||||||||||
| Net oil production per day (MBbl/d)6 | 109 | 107 | 109 | 80 | |||||||||||
| Realized oil price without derivative settlements ($ per Bbl) | $ | 61.14 | $ | 66.32 | $ | 66.52 | $ | 76.92 | |||||||
| Realized oil price with derivative settlements1($ per Bbl)1 | $ | 64.27 | $ | 67.04 | $ | 67.51 | $ | 75.66 | |||||||
| Net NGL production per day (MBbl/d)6 | 9 | 10 | 10 | 10 | |||||||||||
| Realized NGL price ($ per Bbl) | $ | 42.86 | $ | 41.04 | $ | 45.30 | $ | 48.93 | |||||||
| Net natural gas production per day (Mmcf/d)6 | 113 | 118 | 114 | 117 | |||||||||||
| Realized natural gas price ($ per Mcf) | $ | 3.91 | $ | 3.47 | $ | 3.57 | $ | 2.99 | |||||||
| Net total production per day (MBoe/d)6 | 137 | 137 | 138 | 110 | |||||||||||
| Margin from purchased commodities1 | $ | 13 | $ | 14 | $ | 56 | $ | 42 | |||||||
| Electricity margin1 | $ | 40 | $ | 90 | $ | 195 | $ | 119 | |||||||
| Net gain (loss) from commodity derivatives | $ | 126 | $ | (23 | ) | $ | 266 | $ | 241 | ||||||
| Other operating expenses net of other revenue1 | $ | 75 | $ | 25 | $ | 187 | $ | 213 | |||||||
| Select Financial Statement Data and Non-GAAP Measures: | 4th Quarter | 3rd Quarter | Total Year | Total Year | ||||||||||
| ($ and shares in millions, except per share amounts) | 2025 | 2025 | 2025 | 2024 | ||||||||||
| Total operating revenues | $ | 924 | $ | 855 | $ | 3,669 | $ | 3,198 | ||||||
| Operating costs | $ | 325 | $ | 316 | $ | 1,252 | $ | 966 | ||||||
| General and administrative expenses | $ | 95 | $ | 87 | $ | 333 | $ | 321 | ||||||
| Adjusted general and administrative expenses1 | $ | 89 | $ | 82 | $ | 309 | $ | 279 | ||||||
| Taxes other than on income | $ | 55 | $ | 70 | $ | 242 | $ | 242 | ||||||
| Transportation costs | $ | 20 | $ | 19 | $ | 79 | $ | 81 | ||||||
| Operating income | $ | 47 | $ | 98 | $ | 598 | $ | 620 | ||||||
| Interest and debt expense, net | $ | 29 | $ | 25 | $ | 106 | $ | 87 | ||||||
| Income tax provision | $ | 11 | $ | 11 | $ | 139 | $ | 140 | ||||||
| Deferred income tax provision | $ | 22 | $ | 35 | $ | 98 | $ | 71 | ||||||
| Net income | $ | 12 | $ | 64 | $ | 363 | $ | 376 | ||||||
| Weighted-average common shares outstanding - diluted | 85.1 | 84.4 | 87.4 | 81.4 | ||||||||||
| Net income per share - diluted | $ | 0.14 | $ | 0.76 | $ | 4.15 | $ | 4.62 | ||||||
| Adjusted net income1 | $ | 40 | $ | 123 | $ | 359 | $ | 317 | ||||||
| Adjusted net income per share1- diluted | $ | 0.47 | $ | 1.46 | $ | 4.11 | $ | 3.89 | ||||||
| Net cash provided by operating activities | $ | 235 | $ | 279 | $ | 865 | $ | 610 | ||||||
| Adjusted EBITDAX1 | $ | 251 | $ | 338 | $ | 1,241 | $ | 1,006 | ||||||
| Free cash flow1 | $ | 115 | $ | 188 | $ | 543 | $ | 355 | ||||||
| Capital investments | $ | 120 | $ | 91 | $ | 322 | $ | 255 | ||||||
| Cash and cash equivalents (as of December 31, 2025 and 2024, respectively) | $ | 132 | $ | 372 | ||||||||||
| Available cash and cash equivalents | $ | 117 | $ | 354 | ||||||||||
| Restricted cash | $ | 15 | $ | 18 | ||||||||||
2025 Proved Reserves
As of December 31, 2025, CRC's total proved reserves were 654 million Boe (MMBoe), of which approximately 83% was oil and 541 MMBoe was proved developed. CRC added 93 MMBoe of proved reserves related to the Berry merger in 2025. Standardized measure of discounted future net cash flows were $6,666 million with a PV-101 value of $8,717 million, based on SEC pricing, at December 31, 2025. In 2025, CRC's reserve replacement ratio1 was 368%. See Attachment 3 for the non-GAAP reconciliation.
2026 Guidance
The following table provides key first quarter and full year 2026 financial and operating guidance6. In 2026, CRC expects to operate a four-rig program subject to commodity prices and market conditions. CRC currently holds the permits necessary to execute a majority of its planned capital program. See Attachment 2 for further information on CRC's first quarter and full year 2026 guidance.
| 1Q26E |
Total Year 2026E |
|
| Net Production (MBoe/d) | 155 - 157 | 152 - 157 |
| Percentage Oil | 81% | 1 |
| Capital Investments ($ millions) | $110 - $130 | $430 - $470 |
| Adjusted EBITDAX1($ millions) | $240 - $280 | $970 - $1,070 |
Shareholder Returns
CRC is committed to increasing shareholder returns over time. In November 2025, CRC increased its annual dividend by approximately 5% to a total annual dividend of $1.62. CRC has increased its dividend every year since 2021.
On March 1, 2026, CRC's Board of Directors declared a quarterly cash dividend of $0.405 per share of common stock, payable to shareholders of record on March 13, 2026. The dividend is expected to be paid on March 20, 2026.
In 2025, CRC repurchased 8.3 million shares of its common stock for $377 million2 at an average price of $45.29 per share and returned $136 million in dividends to shareholders. Since mid-2021, the Company has returned approximately $1,573 million to shareholders2, including $1,170 million in share repurchases and $403 million in dividends.
In February 2026, CRC’s Board of Directors approved an increase of the Share Repurchase Program to $1.78 billion, an increase of $430 million and extended the program through December 31, 2027. After this increase and repurchases in January 2026, CRC has $600 million of capacity remaining under the repurchase program as of February 28, 2026.
Balance Sheet and Liquidity
In October 2025, CRC's lenders reaffirmed its $1,500 million borrowing base under its Revolving Credit Facility as part of its semi-annual redetermination. In December 2025, elected commitments under the Revolving Credit Facility increased by $10 million to $1,460 million.
At year-end 2025, CRC had liquidity of $1,401 million, consisting of $117 million in available cash and cash equivalents3 and $1,284 million of available borrowing capacity under its Revolving Credit Facility (which reflects $1,460 million of borrowing capacity less $176 million of outstanding letters of credit). There were no outstanding borrowings under the Revolving Credit Facility as of December 31, 2025.
Participation in Upcoming Investor Conferences
CRC is scheduled to participate in the following events in March 2026:
- 2026 Jefferies Power, Energy, Clean Energy, and Utilities Conference, March 4, New York, NY
- 2026 NYSE Investor Access Day, March 20, Virtual
- 38th Annual ROTH Conference, March 23, Dana Point, CA
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 Monday, March 2, 2026. To participate in the call, dial (877) 328-5505 (International calls dial +1 (412) 317-5421) or access via webcast at www.crc.com. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10204776/10070090c28. A digital replay of the conference call will be available for approximately 90 days.
1 See Attachment 3 for the non-GAAP financial measures of adjusted net income (loss), adjusted net income (loss) per share - basic and diluted, net cash provided by operating activities before changes in operating assets and liabilities, net, adjusted EBITDAX, free cash flow, adjusted general and administrative expenses and PV-10 including reconciliations to the most directly comparable GAAP measure without unreasonable effort. See Attachment 2 for the 1Q26 and 2026 estimates of the non-GAAP measures of adjusted EBITDAX, oil and natural gas segment adjusted EBITDAX, carbon management segment adjusted EBITDAX and adjusted general and administrative expenses, including reconciliations to its most directly comparable GAAP measure, without unreasonable effort. See Attachment 1 for a reconciliation of drilling completion and workover capital to total capital investments reported under GAAP.
2 All of CRC’s future quarterly dividends and share repurchases are subject to commodity prices, debt agreement covenants and Board of Directors' approval. The total value of shares purchased excludes commissions and excise taxes. Commissions paid on share repurchases were not significant in all periods presented. The total value of share repurchases excludes excise taxes of approximately $2 million in the year ended December 31, 2024. Excise taxes were insignificant in the year ended December 31, 2025. The total value of shares repurchased excludes approximately $3 million related to excise taxes and commissions paid on share repurchases since the inception of the Share Repurchase Program.
3 Excludes restricted cash of $15 million.
4 MOUs and CDMAs are non-binding agreements. The projects and transactions described in an MOU or CDMA 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 Net production per day for the periods presented reflects the impact of transaction timing. Aera Energy volumes contributed for the full year in 2025 and for approximately six months in 2024, while Berry Corporation volumes contributed for approximately 14 days in 2025 following the transaction close. Production amounts shown are reported results and are not presented on a pro forma basis.
6 1Q26 guidance assumes Brent price of $66.42 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $5.22 per mcf. Total year 2026 guidance assumes Brent price of $65.57 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $4.13 per mcf.
About California Resources Corporation
California Resources Corporation (CRC) is an independent energy and carbon management company advancing the energy transition. CRC is committed to environmental stewardship while safely providing local, responsibly sourced energy. CRC is also focused on maximizing the value of its land, mineral ownership, and energy expertise for decarbonization by developing CCS and other emissions reducing projects. For more information about CRC, please visit 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.
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 synergies and other benefits in connection with the Berry 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 or prevent oil and gas activities or the development of CRC’s carbon management segment; changes in business strategy and the ability and financial resources to execute our capital plan in a timely manner; lower-than-expected production; changes to estimates of reserves and related future cash flows; the recoverability of resources and unexpected geologic conditions; general economic conditions and trends; results from operations and competition in the industries in which it operates; CRC’s ability to realize the anticipated benefits from prior or future efforts to reduce costs; environmental risks and liability; the benefits contemplated by its energy transition strategies and initiatives; CRC’s ability to successfully identify, develop and finance carbon capture and storage projects, power projects and other renewable energy efforts; delays from government approvals and otherwise that could affect the timing of first injection of CO2; future dividends and share repurchases and de-leveraging efforts; and natural disasters, accidents, mechanical failures, power outages, labor difficulties, cybersecurity breaches or attacks or other catastrophic events.
CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the date hereof, and CRC is under no obligation, and expressly disclaims any obligation to update, alter or otherwise revise any forward-looking statements, whether as a result of new information, future events or otherwise. This communication may also contain information from third-party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and does not warrant the accuracy or completeness of such third-party information.
Contacts:
| Daniel Juck (Investor Relations) 818-661-3700 IR@crc.com |
Hailey Bonus (Media) 714-874-7732 CRC.Communications@crc.com |
| Attachment 1 | ||||||||||||||||||||
| STATEMENTS OF OPERATIONS, SELECT FINANCIAL INFORMATION | ||||||||||||||||||||
|
($ and shares in millions, except per share amounts) |
4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | |||||||||||||||
| 2025 | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||
| Statements of Operations: | ||||||||||||||||||||
| Revenues | ||||||||||||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 679 | $ | 715 | $ | 826 | $ | 2,910 | $ | 2,537 | ||||||||||
| Net gain (loss) from commodity derivatives | 126 | (23 | ) | (49 | ) | 266 | 241 | |||||||||||||
| Revenue from marketing of purchased commodities | 60 | 58 | 59 | 238 | 235 | |||||||||||||||
| Electricity sales | 52 | 101 | 39 | 233 | 159 | |||||||||||||||
| Other revenue | 7 | 4 | 2 | 22 | 26 | |||||||||||||||
| Total operating revenues | 924 | 855 | 877 | 3,669 | 3,198 | |||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operating costs | 325 | 316 | 323 | 1,252 | 966 | |||||||||||||||
| General and administrative expenses | 95 | 87 | 95 | 333 | 321 | |||||||||||||||
| Depreciation, depletion and amortization | 129 | 123 | 142 | 511 | 388 | |||||||||||||||
| Asset impairment | 57 | 2 | 1 | 59 | 14 | |||||||||||||||
| Taxes other than on income | 55 | 70 | 80 | 242 | 242 | |||||||||||||||
| Costs related to marketing of purchased commodities | 47 | 44 | 53 | 182 | 193 | |||||||||||||||
| Electricity generation expenses | 12 | 11 | 9 | 38 | 40 | |||||||||||||||
| Transportation costs | 20 | 19 | 21 | 79 | 81 | |||||||||||||||
| Accretion expense | 29 | 28 | 31 | 114 | 87 | |||||||||||||||
| Net loss on natural gas purchase derivatives | 26 | 27 | 19 | 50 | 30 | |||||||||||||||
| Measurement period adjustments, net | — | — | (12 | ) | 1 | (12 | ) | |||||||||||||
| Other operating expenses, net | 82 | 29 | 51 | 209 | 239 | |||||||||||||||
| Total operating expenses | 877 | 756 | 813 | 3,070 | 2,589 | |||||||||||||||
| (Loss) gain on asset divestitures | — | (1 | ) | 4 | (1 | ) | 11 | |||||||||||||
| Operating Income | 47 | 98 | 68 | 598 | 620 | |||||||||||||||
| Non-Operating (Expenses) Income | ||||||||||||||||||||
| Interest and debt expense, net | (29 | ) | (25 | ) | (28 | ) | (106 | ) | (87 | ) | ||||||||||
| Equity loss from unconsolidated subsidiaries | (1 | ) | (2 | ) | (1 | ) | (4 | ) | (10 | ) | ||||||||||
| Loss on early extinguishment of debt | — | — | — | (1 | ) | (5 | ) | |||||||||||||
| Other non-operating income (expense), net | 6 | 4 | 2 | 15 | (2 | ) | ||||||||||||||
| Income Before Income Taxes | 23 | 75 | 41 | 502 | 516 | |||||||||||||||
| Income tax provision | (11 | ) | (11 | ) | (8 | ) | (139 | ) | (140 | ) | ||||||||||
| Net Income | $ | 12 | $ | 64 | $ | 33 | $ | 363 | $ | 376 | ||||||||||
| Net income per share - basic | $ | 0.14 | $ | 0.76 | $ | 0.36 | $ | 4.17 | $ | 4.74 | ||||||||||
| Net income per share - diluted | $ | 0.14 | $ | 0.76 | $ | 0.36 | $ | 4.15 | $ | 4.62 | ||||||||||
| Adjusted net income | $ | 40 | $ | 123 | $ | 84 | $ | 359 | $ | 317 | ||||||||||
| Adjusted net income per share - basic | $ | 0.47 | $ | 1.47 | $ | 0.93 | $ | 4.13 | $ | 4.00 | ||||||||||
| Adjusted net income per share - diluted | $ | 0.47 | $ | 1.46 | $ | 0.91 | $ | 4.11 | $ | 3.89 | ||||||||||
| Weighted-average common shares outstanding - basic | 84.6 | 83.7 | 90.8 | 87.0 | 79.3 | |||||||||||||||
| Weighted-average common shares outstanding - diluted | 85.1 | 84.4 | 92.2 | 87.4 | 81.4 | |||||||||||||||
| Effective tax rate | 48 | % | 15 | % | 20 | % | 28 | % | 27 | % | ||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ in millions) | 2025 | 2025 | 2024 | 2025 | 2024 | |||||||||||||||
| Cash Flow Data: | ||||||||||||||||||||
| Net cash provided by operating activities | $ | 235 | $ | 279 | $ | 206 | $ | 865 | $ | 610 | ||||||||||
| Net cash used in investing activities | $ | (508 | ) | $ | (87 | ) | $ | (67 | ) | $ | (725 | ) | $ | (1,077 | ) | |||||
| Net cash provided by (used in) financing activities | $ | 209 | $ | (68 | ) | $ | (8 | ) | $ | (380 | ) | $ | 343 | |||||||
| December 31, | December 31, | |||||||||||||||||||
| ($ in millions) | 2025 | 2024 | ||||||||||||||||||
| Select Balance Sheet Information: | ||||||||||||||||||||
| Total current assets | $ | 938 | $ | 1,024 | ||||||||||||||||
| Property, plant and equipment, net | $ | 5,905 | $ | 5,680 | ||||||||||||||||
| Total current liabilities | $ | 1,050 | $ | 980 | ||||||||||||||||
| Long-term debt, net | $ | 1,283 | $ | 1,132 | ||||||||||||||||
| Noncurrent asset retirement obligations | $ | 913 | $ | 995 | ||||||||||||||||
| Total stockholders' equity | $ | 3,674 | $ | 3,538 | ||||||||||||||||
|
GAINS AND LOSSES FROM COMMODITY DERIVATIVES | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ millions) | 2025 | 2025 | 2024 | 2025 | 2024 | |||||||||||||||
| Non-cash commodity derivative gain (loss) | $ | 95 | $ | (32 | ) | $ | (51 | ) | $ | 225 | $ | 274 | ||||||||
| Net received (paid) on settled commodity derivatives | 31 | 9 | 2 | 41 | (33 | ) | ||||||||||||||
| Net gain (loss) from commodity derivatives | $ | 126 | $ | (23 | ) | $ | (49 | ) | $ | 266 | $ | 241 | ||||||||
| Non-cash derivative loss (gain) | $ | 22 | $ | 24 | $ | 5 | $ | 24 | $ | (2 | ) | |||||||||
| Net paid on settled commodity derivatives | 4 | 3 | 14 | 26 | 32 | |||||||||||||||
| Net loss on natural gas purchase derivatives | $ | 26 | $ | 27 | $ | 19 | $ | 50 | $ | 30 | ||||||||||
| CAPITAL INVESTMENTS | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ millions) | 2025 | 2025 | 2024 | 2025 | 2024 | |||||||||||||||
| Facilities(1) | $ | 46 | $ | 28 | $ | 44 | $ | 99 | $ | 111 | ||||||||||
| Drilling and completions | 38 | 26 | 17 | 98 | 69 | |||||||||||||||
| Workovers | 18 | 17 | 17 | 69 | 54 | |||||||||||||||
| Other | 9 | 1 | — | 10 | — | |||||||||||||||
| Oil and natural gas segment | 111 | 72 | 78 | 276 | 234 | |||||||||||||||
| Carbon management segment | 11 | 15 | 6 | 33 | 12 | |||||||||||||||
| Corporate and other(1) | (2 | ) | 4 | 4 | 13 | 9 | ||||||||||||||
| Total capital investment | $ | 120 | $ | 91 | $ | 88 | $ | 322 | $ | 255 | ||||||||||
| (1) Certain amounts previously reported in the Q1 2025 earnings release have been corrected. This correction relates to reporting of $8 million of capital as Corporate and other in Q1 2025 and this amount was reclassified to Facilities in Q4 2025. | ||||||||||||||||||||
| LIQUIDITY | ||||||||
| ($ millions) | December 31, 2025 | December 31, 2024 | ||||||
| Available cash and cash equivalents(1) | $ | 117 | $ | 354 | ||||
| Revolving credit facility: | ||||||||
| Borrowing capacity | 1,460 | 1,150 | ||||||
| Outstanding letters of credit | (176 | ) | (167 | ) | ||||
| Availability | $ | 1,284 | $ | 983 | ||||
| Liquidity | $ | 1,401 | $ | 1,337 | ||||
| (1) Excludes restricted cash of $15 million and $18 million at December 31, 2025 and December 31, 2024, respectively. | ||||||||
| Attachment 2 | ||||||
| CRC GUIDANCE |
Consolidated 1Q26E |
Oil and Natural Gas Segment |
Carbon Management Segment |
|||
| Net production (MBoe/d) | 155 - 157 | |||||
| Net oil production (%) | 81% | |||||
| Operating costs ($ millions) | $355 - $375 | $355 - $375 | ||||
| General and administrative expenses ($ millions) | $90 - $100 | $12 - $16 | $2 - $4 | |||
| Adjusted general and administrative expenses ($ millions) | $85 - $90 | $12 - $16 | $2 - $4 | |||
| Depreciation, depletion and amortization ($ millions) | $145 - $157 | $140 - $150 | ||||
| Capital investments ($ millions) | $110 - $130 | $95 - $110 | $12 - $16 | |||
| Adjusted EBITDAX ($ millions) | $240 - $280 | $290 - $325 | $(10) - $(5) | |||
| Margin from purchased commodities ($ millions)(1) | $15 - $20 | |||||
| Electricity revenue ($ millions) | $6 - $16 | |||||
| Electricity generation expenses ($ millions) | $2 - $6 | |||||
| Other operating expenses net of other revenue ($ millions)(2) | $10 - $20 | $2 - $10 | ||||
| Transportation costs ($ millions) | $25 - $30 | $15 - $20 | ||||
| Taxes other than on income ($ millions) | $65 - $75 | $60 - $65 | ||||
| Interest and debt expense ($ millions) | $30 - $35 | |||||
| Other Assumptions: | ||||||
| Brent ($/Bbl) | $66.42 | |||||
| NYMEX ($/Mcf) | $5.22 | |||||
| Price realization oil - % of Brent: | 94% - 98% | |||||
| Price realization NGLs - % of Brent: | 60% - 66% | |||||
| Price realization natural gas - % of NYMEX: | 58% - 64% | |||||
| Deferred income taxes | 62% - 74% | |||||
| Effective tax rate | 32% | |||||
| CRC GUIDANCE |
Consolidated 2026E |
Oil and Natural Gas Segment |
Carbon Management Segment |
|||
| Net production (MBoe/d) | 152 - 157 | |||||
| Net oil production (%) | 81% | |||||
| Operating costs ($ millions) | $1,400 - $1,500 | $1,400 - $1,500 | ||||
| General and administrative expenses ($ millions) | $350 - $370 | $50 - $60 | $6 - $12 | |||
| Adjusted general and administrative expenses ($ millions) | $315 - $330 | $50 - $60 | $6 - $12 | |||
| Depreciation, depletion and amortization ($ millions) | $595 - $615 | $575 - $590 | ||||
| Capital investments ($ millions) | $430 - $470 | $410 - $435 | $12 - $20 | |||
| Adjusted EBITDAX ($ millions) | $970 - $1,070 | $1,215 - $1,305 | $(50) - $(10) | |||
| Margin from purchased commodities ($ millions)(1) | $60 - $75 | |||||
| Electricity revenue ($ millions) | $55 - $85 | |||||
| Electricity generation expenses ($ millions) | $15 - $25 | |||||
| Other operating expenses net of other revenue ($ millions)(2) | $20 - $30 | $25 - $35 | ||||
| Transportation costs ($ millions) | $105 - $115 | $65 - $70 | ||||
| Taxes other than on income ($ millions) | $275 - $285 | $240 - $250 | ||||
| Interest and debt expense ($ millions) | $125 - $135 | |||||
| Other Assumptions: | ||||||
| Brent ($/Bbl) | $65.57 | |||||
| NYMEX ($/Mcf) | $4.13 | |||||
| Price realization oil - % of Brent: | 94% - 98% | |||||
| Price realization NGLs - % of Brent: | 55% - 60% | |||||
| Price realization natural gas - % of NYMEX: | 65% - 70% | |||||
| Deferred income taxes | 62% - 74% | |||||
| Effective tax rate | 32% | |||||
| (1) Margin from purchased commodities is calculated as the difference between revenue from marketing of purchased commodities and costs related to marketing of purchased commodities, and excludes costs of transportation. | ||||||
| (2) Other operating revenue and expenses, net is calculated as the difference between other revenue and other operating expenses, net and includes exploration expense and CMB expenses. CMB expenses includes lease cost for sequestration easements, advocacy, and other startup related costs. | ||||||
| See Attachment 3 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition. | ||||||
|
FORWARD LOOKING NON-GAAP RECONCILIATIONS A reconciliation of the non-GAAP measure of segment adjusted EBITDAX cannot be reconciled to the comparable measure of operating cash flow prepared in accordance with GAAP without unreasonable effort. We have included a reconciliation of the GAAP measure of segment profit to segment adjusted EBITDAX. | ||||||||||||||||||||
| 1Q26E | ||||||||||||||||||||
| Consolidated |
Oil and Natural Gas Segment |
Carbon Management Segment |
||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | ||||||||||||||
| General and administrative expenses | $ | 90 | $ | 100 | $ | 12 | $ | 16 | $ | 2 | $ | 4 | ||||||||
| Equity-settled stock-based compensation | (5 | ) | (10 | ) | — | — | — | — | ||||||||||||
| Estimated adjusted general and administrative expenses | $ | 85 | $ | 90 | $ | 12 | $ | 16 | $ | 2 | $ | 4 | ||||||||
| Consolidated | ||||||
| 1Q26E | ||||||
| ($ millions) | Low | High | ||||
| Net income | $ | 5 | $ | 13 | ||
| Interest and debt expense | 30 | 35 | ||||
| Depreciation, depletion and amortization | 145 | 157 | ||||
| Income taxes | 2 | 6 | ||||
| Exploration expense | 1 | 1 | ||||
| Loss from investment on unconsolidated subsidiaries | — | 2 | ||||
| Unusual, infrequent and other items | 23 | 28 | ||||
| Other non-cash items | ||||||
| Accretion expense | 25 | 29 | ||||
| Stock-settled compensation | 9 | 9 | ||||
| Estimated adjusted EBITDAX | $ | 240 | $ | 280 | ||
| Net cash provided by operating activities | $ | 98 | $ | 110 | ||
| Cash interest | — | 4 | ||||
| Cash income taxes | 3 | 9 | ||||
| Working capital changes | 139 | 157 | ||||
| Estimated adjusted EBITDAX | $ | 240 | $ | 280 | ||
| Oil and Natural Gas Segment | ||||||
| 1Q26E | ||||||
| ($ millions) | Low | High | ||||
| Segment profit | $ | 122 | $ | 142 | ||
| Depreciation, depletion and amortization | 140 | 150 | ||||
| Unusual, infrequent and other items | 3 | 4 | ||||
| Other non-cash items | ||||||
| Accretion expense | 25 | 29 | ||||
| Estimated adjusted EBITDAX | $ | 290 | $ | 325 | ||
| Carbon Management Segment | ||||||||
| 1Q26E | ||||||||
| ($ millions) | Low | High | ||||||
| Segment loss | $ | (7 | ) | $ | (18 | ) | ||
| Interest and debt expense, net | 1 | 5 | ||||||
| Loss from investment on unconsolidated subsidiary | 1 | 3 | ||||||
| Estimated adjusted EBITDAX | $ | (5 | ) | $ | (10 | ) | ||
| Consolidated | ||||||||
| 1Q26E | ||||||||
| ($ millions) | Low | High | ||||||
| Revenue from marketing of purchased commodities | $ | 54 | $ | 70 | ||||
| Costs related to marketing of purchased commodities | (39 | ) | (50 | ) | ||||
| Margin from purchased commodities | $ | 15 | $ | 20 | ||||
| Consolidated | ||||||||
| 1Q26E | ||||||||
| ($ millions) | Low | High | ||||||
| Other operating expenses, net | $ | 38 | $ | 54 | ||||
| Other revenue | (28 | ) | (34 | ) | ||||
| Operating expenses net of other revenue | $ | 10 | $ | 20 | ||||
| 2026E | ||||||||||||||||||||
| Consolidated |
Oil and Natural Gas Segment |
Carbon Management Segment |
||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | ||||||||||||||
| General and administrative expenses | $ | 350 | $ | 370 | $ | 50 | $ | 60 | $ | 6 | $ | 12 | ||||||||
| Equity-settled stock-based compensation | (35 | ) | (40 | ) | — | — | — | — | ||||||||||||
| Estimated adjusted general and administrative expenses | $ | 315 | $ | 330 | $ | 50 | $ | 60 | $ | 6 | $ | 12 | ||||||||
| Consolidated | ||||||||
| 2026E | ||||||||
| ($ millions) | Low | High | ||||||
| Net income | $ | 50 | $ | 80 | ||||
| Interest and debt expense | 125 | 135 | ||||||
| Interest income | (2 | ) | — | |||||
| Depreciation, depletion and amortization | 595 | 615 | ||||||
| Income taxes | 22 | 30 | ||||||
| Exploration expense | 5 | 5 | ||||||
| Loss from investment on unconsolidated subsidiaries | 1 | 3 | ||||||
| Unusual, infrequent and other items | 33 | 51 | ||||||
| Other non-cash items | ||||||||
| Accretion expense | 105 | 115 | ||||||
| Stock-settled compensation | 36 | 36 | ||||||
| Estimated adjusted EBITDAX | $ | 970 | $ | 1,070 | ||||
| Net cash provided by operating activities | $ | 620 | $ | 644 | ||||
| Cash interest | 100 | 116 | ||||||
| Cash income taxes | (34 | ) | (22 | ) | ||||
| Working capital changes | 284 | 332 | ||||||
| Estimated adjusted EBITDAX | $ | 970 | $ | 1,070 | ||||
| Oil and Natural Gas Segment | ||||||
| 2026E | ||||||
| ($ millions) | Low | High | ||||
| Segment profit | $ | 528 | $ | 588 | ||
| Depreciation, depletion and amortization | 575 | 590 | ||||
| Unusual, infrequent and other items | 7 | 12 | ||||
| Other non-cash items | ||||||
| Accretion expense | 105 | 115 | ||||
| Estimated adjusted EBITDAX | $ | 1,215 | $ | 1,305 | ||
| Carbon Management Segment | ||||||||
| 2026E | ||||||||
| ($ millions) | Low | High | ||||||
| Segment loss | $ | (19 | ) | $ | (77 | ) | ||
| Interest and debt expense, net | 6 | 18 | ||||||
| Loss from investment on unconsolidated subsidiary | 3 | 9 | ||||||
| Estimated adjusted EBITDAX | $ | (10 | ) | $ | (50 | ) | ||
| Consolidated | ||||||||
| 2026E | ||||||||
| ($ millions) | Low | High | ||||||
| Revenue from marketing of purchased commodities | $ | 240 | $ | 265 | ||||
| Costs related to marketing of purchased commodities | (180 | ) | (190 | ) | ||||
| Margin from purchased commodities | $ | 60 | $ | 75 | ||||
| Consolidated | ||||||||
| 2026E | ||||||||
| ($ millions) | Low | High | ||||||
| Other operating expenses, net | $ | 166 | $ | 184 | ||||
| Other revenue | (146 | ) | (154 | ) | ||||
| Operating expenses net of other revenue | $ | 20 | $ | 30 | ||||
| Attachment 3 |
| NON-GAAP RECONCILIATIONS |
| To supplement the presentation of its financial results prepared in accordance with U.S. generally accepted accounting principles (GAAP), management uses certain non-GAAP measures to assess its financial condition, results of operations and cash flows. These measures are also widely used by the industry, the investment community and CRC's lenders. Although these are non-GAAP measures, the amounts included in the calculations were computed in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing CRC's financial performance, such as CRC's cost of capital and tax structure, as well as the effect of acquisition and development costs of CRC's assets. Management believes that the non-GAAP measures presented, when viewed in combination with CRC's financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the Company's performance. The non-GAAP measures presented herein may not be comparable to other similarly titled measures of other companies. Below are additional disclosures regarding each of these non-GAAP measures, including reconciliations to their most directly comparable GAAP measure where applicable. |
| ADJUSTED NET INCOME (LOSS) | ||||||||||||||||||||
| Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. CRC defines adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing CRC's financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income and net income attributable to common stock per share to the non-GAAP financial measures of adjusted net income and adjusted net income per share. | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ millions, except per share amounts) | 2025 | 2025 | 2024 | 2025 | 2024 | |||||||||||||||
| Net income | $ | 12 | $ | 64 | $ | 33 | $ | 363 | $ | 376 | ||||||||||
| Unusual, infrequent and other items: | ||||||||||||||||||||
| Non-cash derivative (gain) loss on Brent based commodity contracts | (95 | ) | 32 | 51 | (225 | ) | (274 | ) | ||||||||||||
| Non-cash derivative loss (gain) on natural gas derivative contracts | 22 | 24 | 5 | 24 | (2 | ) | ||||||||||||||
| Asset impairment | 57 | 2 | 1 | 59 | 14 | |||||||||||||||
| Severance and termination costs | 12 | — | 2 | 20 | 30 | |||||||||||||||
| Merger-related costs | 20 | 6 | 1 | 30 | 57 | |||||||||||||||
| Increased power and fuel costs due to power plant maintenance | — | — | 6 | — | 50 | |||||||||||||||
| Net loss (gain) on asset divestitures | — | 1 | (4 | ) | 1 | (11 | ) | |||||||||||||
| Loss on early extinguishment of debt | — | — | — | 1 | 5 | |||||||||||||||
| Offshore platform expense | 12 | 5 | 2 | 19 | 5 | |||||||||||||||
| Litigation and settlements | — | 1 | 5 | 26 | 12 | |||||||||||||||
| Measurement period adjustments | — | — | — | 1 | — | |||||||||||||||
| Other, net | 11 | 11 | 1 | 38 | 23 | |||||||||||||||
| Total unusual, infrequent and other items | 39 | 82 | 70 | (6 | ) | (91 | ) | |||||||||||||
| Income tax (benefit) provision of adjustments at the combined tax rate | (11 | ) | (23 | ) | (19 | ) | 2 | 32 | ||||||||||||
| Adjusted net income | $ | 40 | $ | 123 | $ | 84 | $ | 359 | $ | 317 | ||||||||||
| Net income (loss) per share – basic | $ | 0.14 | $ | 0.76 | $ | 0.36 | $ | 4.17 | $ | 4.74 | ||||||||||
| Net income (loss) per share – diluted | $ | 0.14 | $ | 0.76 | $ | 0.36 | $ | 4.15 | $ | 4.62 | ||||||||||
| Adjusted net income per share – basic | $ | 0.47 | $ | 1.47 | $ | 0.93 | $ | 4.13 | $ | 4.00 | ||||||||||
| Adjusted net income per share – diluted | $ | 0.47 | $ | 1.46 | $ | 0.91 | $ | 4.11 | $ | 3.89 | ||||||||||
| 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 below. Management believes these segment non-GAAP measures are useful for investors to understand the results of our core businesses. | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ millions, except per BOE amounts) | 2025 | 2025 | 2024 | 2025 | 2024 | |||||||||||||||
| Net income | $ | 12 | $ | 64 | $ | 33 | $ | 363 | $ | 376 | ||||||||||
| Interest and debt expense | 29 | 25 | 28 | 106 | 87 | |||||||||||||||
| Depreciation, depletion and amortization | 129 | 123 | 142 | 511 | 388 | |||||||||||||||
| Income tax provision | 11 | 11 | 8 | 139 | 140 | |||||||||||||||
| Exploration expense | 1 | — | — | 2 | 2 | |||||||||||||||
| Interest income | (5 | ) | (1 | ) | (4 | ) | (11 | ) | (19 | ) | ||||||||||
| Equity loss from unconsolidated subsidiaries | 1 | 2 | — | 4 | — | |||||||||||||||
| Unusual, infrequent and other items(1) | 39 | 82 | 70 | (6 | ) | (91 | ) | |||||||||||||
| Non-cash items | ||||||||||||||||||||
| Accretion expense | 29 | 28 | 31 | 114 | 87 | |||||||||||||||
| Stock-based compensation | 6 | 5 | 6 | 24 | 23 | |||||||||||||||
| Taxes related to acquisition accounting and other | — | — | 2 | — | 12 | |||||||||||||||
| Pension and post-retirement benefits | (1 | ) | (1 | ) | — | (5 | ) | 1 | ||||||||||||
| Adjusted EBITDAX | $ | 251 | $ | 338 | $ | 316 | $ | 1,241 | $ | 1,006 | ||||||||||
| Net cash provided by operating activities | $ | 235 | $ | 279 | $ | 206 | $ | 865 | $ | 610 | ||||||||||
| Cash interest payments | 42 | 6 | 42 | 98 | 88 | |||||||||||||||
| Cash interest received | (5 | ) | (1 | ) | (4 | ) | (11 | ) | (19 | ) | ||||||||||
| Cash income taxes | — | 6 | 50 | 45 | 105 | |||||||||||||||
| Exploration expense | 1 | — | — | 2 | 2 | |||||||||||||||
| Working capital changes | (22 | ) | 48 | 22 | 242 | 220 | ||||||||||||||
| Adjusted EBITDAX | $ | 251 | $ | 338 | $ | 316 | $ | 1,241 | $ | 1,006 | ||||||||||
| Net income per Boe | $ | 0.95 | $ | 5.09 | $ | 2.54 | $ | 7.21 | $ | 9.38 | ||||||||||
| Adjusted EBITDAX per Boe | $ | 19.85 | $ | 26.90 | $ | 24.35 | $ | 24.65 | $ | 25.09 | ||||||||||
| (1) See Adjusted Net Income (Loss) reconciliation. | ||||||||||||||||||||
| SEGMENT ADJUSTED EBITDAX | ||||||||||||||||||||
| 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 and Natural Gas Segment | 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | |||||||||||||||
| ($ millions) | 2025 | 2025 | 2024 | 2025 | 2024(1) | |||||||||||||||
| Segment profit | $ | 46 | $ | 182 | $ | 268 | $ | 688 | $ | 815 | ||||||||||
| Depreciation, depletion and amortization | 127 | 118 | 129 | 492 | 354 | |||||||||||||||
| Exploration expense | 1 | — | — | 2 | 2 | |||||||||||||||
| Accretion expense | 29 | 28 | 31 | 114 | 87 | |||||||||||||||
| Adjusted income items | 16 | 4 | (3 | ) | 23 | 54 | ||||||||||||||
| Adjusted EBITDAX - Oil and Natural Gas | $ | 219 | $ | 332 | $ | 425 | $ | 1,319 | $ | 1,312 | ||||||||||
| Carbon Management Segment | ||||||||||||||||||||
| Segment loss | $ | (20 | ) | $ | (21 | ) | $ | (31 | ) | $ | (86 | ) | $ | (94 | ) | |||||
| Interest on contingent liability (related to Carbon TerraVault JV) | 3 | 3 | 3 | 11 | 9 | |||||||||||||||
| Equity loss from unconsolidated subsidiary | 2 | 2 | 2 | 6 | 5 | |||||||||||||||
| Adjusted income items | 57 | 2 | 1 | 59 | 2 | |||||||||||||||
| Adjusted EBITDAX - Carbon Management | $ | 42 | $ | (14 | ) | $ | (25 | ) | $ | (10 | ) | $ | (78 | ) | ||||||
| (1) Certain amounts related to the total year 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. | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ millions) | 2025 | 2025 | 2024 | 2025 | 2024 | |||||||||||||||
| Net cash provided by operating activities | $ | 235 | $ | 279 | $ | 206 | $ | 865 | $ | 610 | ||||||||||
| Capital investments | (120 | ) | (91 | ) | (88 | ) | (322 | ) | (255 | ) | ||||||||||
| Free cash flow | $ | 115 | $ | 188 | $ | 118 | $ | 543 | $ | 355 | ||||||||||
| 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. | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ millions) | 2025 | 2025 | 2024 | 2025 | 2024 | |||||||||||||||
| General and administrative expenses | $ | 95 | $ | 87 | $ | 95 | $ | 333 | $ | 321 | ||||||||||
| Stock-based compensation | (6 | ) | (5 | ) | (6 | ) | (24 | ) | (23 | ) | ||||||||||
| Information technology infrastructure | — | — | — | — | (3 | ) | ||||||||||||||
| Accelerated vesting | — | — | (3 | ) | — | (12 | ) | |||||||||||||
| Retention awards | — | — | — | — | (2 | ) | ||||||||||||||
| Other | — | — | (1 | ) | — | (2 | ) | |||||||||||||
| Adjusted G&A expenses | $ | 89 | $ | 82 | $ | 85 | $ | 309 | $ | 279 | ||||||||||
| G&A per BOE | $ | 7.51 | $ | 6.92 | $ | 7.32 | $ | 6.61 | $ | 8.01 | ||||||||||
| Adjusted G&A per BOE | $ | 7.04 | $ | 6.52 | $ | 6.55 | $ | 6.14 | $ | 6.96 | ||||||||||
| MARGIN FROM PURCHASED COMMODITIES | ||||||||||||||||||||
| Management uses a measure called margin from purchased commodities, which is calculated as the difference between revenue from purchased commodities and costs related to purchased commodities. This non-GAAP measure excludes transportation costs. | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ millions) | 2025 | 2025 | 2024 | 2025 | 2024 | |||||||||||||||
| Revenue from purchased commodities | $ | 60 | $ | 58 | $ | 59 | $ | 238 | $ | 235 | ||||||||||
| Costs related to purchased commodities | (47 | ) | (44 | ) | (53 | ) | (182 | ) | (193 | ) | ||||||||||
| Margin from purchased commodities | $ | 13 | $ | 14 | $ | 6 | $ | 56 | $ | 42 | ||||||||||
| ELECTRICITY MARGIN | ||||||||||||||||||||
| Management uses a measure called electricity margin, which is calculated as the difference between electricity sales and electricity generation expenses. | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ millions) | 2025 | 2025 | 2024 | 2025 | 2024 | |||||||||||||||
| Electricity sales | $ | 52 | $ | 101 | $ | 39 | $ | 233 | $ | 159 | ||||||||||
| Electricity generation expenses | (12 | ) | (11 | ) | (9 | ) | (38 | ) | (40 | ) | ||||||||||
| Electricity margin | $ | 40 | $ | 90 | $ | 30 | $ | 195 | $ | 119 | ||||||||||
| 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. | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ millions) | 2025 | 2025 | 2024 | 2025 | 2024 | |||||||||||||||
| Other operating expenses, net(1) | $ | 82 | $ | 29 | $ | 51 | $ | 209 | $ | 239 | ||||||||||
| Other revenue | (7 | ) | (4 | ) | (2 | ) | (22 | ) | (26 | ) | ||||||||||
| Other operating expenses net of other revenue | $ | 75 | $ | 25 | $ | 49 | $ | 187 | $ | 213 | ||||||||||
| (1) Other operating expenses, net includes carbon management expenses beginning in 2025. Amounts from 2024 have been represented to conform to the 2025 presentation. | ||||||||||||||||||||
| PV-10 AND STANDARDIZED MEASURE | ||||
| The following table presents a reconciliation of the standardized measure of discounted future net cash flows (Standardized Measure) to the non-GAAP financial measure of PV-10 of cash flows: | ||||
| ($ millions) | As of December 31, 2025 | |||
| Standardized Measure | $ | 6,666 | ||
| Present value of future income taxes discounted at 10% | 2,051 | |||
| PV-10 of cash flows(*) | $ | 8,717 | ||
| (*) PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of oil and natural gas reserves. Standardized Measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing costs and discount assumptions. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity. | ||||
| RESERVE REPLACEMENT RATIO | ||||
| The reserve replacement ratio is a measure that management uses to gauge the growth of its reserves relative to production over the same period. There is no guarantee that historical sources of reserve additions will continue as many factors fully or partially outside management's control, including commodity prices, availability of capital and the underlying geology, affect reserves additions. We calculate the reserve replacement ratio considering reserve additions resulting from extensions and discoveries, improved recovery, revisions in previous estimates related to performance and acquisitions and divestitures. Other oil and gas producers may use different methods to calculate the replacement ratio, which may affect comparability. | ||||
| 2025 |
||||
| (MMBoe) | ||||
| Net performance-related revisions | 61 | |||
| Extensions and discoveries | 3 | |||
| Improved recovery | 27 | |||
| Acquisitions | 93 | |||
| Reserve additions | 184 | |||
| Production (MMboe) | 50 | |||
| Reserve Replacement Ratio | 368 | % | ||
| Attachment 4 | ||||||||||
| PRODUCTION STATISTICS | ||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||
| Net Production Per Day | 2025 | 2025 | 2024 | 2025 | 2024 | |||||
| Oil (MBbl/d) | ||||||||||
| San Joaquin Basin | 82 | 81 | 86 | 83 | 58 | |||||
| Los Angeles Basin | 17 | 17 | 17 | 17 | 17 | |||||
| Uinta Basin | 1 | — | — | — | — | |||||
| Other Basins | 9 | 9 | 9 | 9 | 5 | |||||
| Total | 109 | 107 | 112 | 109 | 80 | |||||
| NGLs (MBbl/d) | ||||||||||
| San Joaquin Basin | 9 | 10 | 10 | 10 | 10 | |||||
| Total | 9 | 10 | 10 | 10 | 10 | |||||
| Natural Gas (MMcf/d) | ||||||||||
| San Joaquin Basin | 97 | 103 | 98 | 99 | 99 | |||||
| Los Angeles Basin | 1 | 1 | 1 | 1 | 1 | |||||
| Sacramento Basin | 11 | 11 | 13 | 12 | 13 | |||||
| Uinta Basin | 1 | — | — | — | — | |||||
| Other Basins | 3 | 3 | 3 | 2 | 4 | |||||
| Total | 113 | 118 | 115 | 114 | 117 | |||||
| Total Net Production (MBoe/d) | 137 | 137 | 141 | 138 | 110 | |||||
| Gross Operated and Net Non-Operated | 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | |||||
| Production Per Day | 2025 | 2025 | 2024 | 2025 | 2024 | |||||
| Oil (MBbl/d) | ||||||||||
| San Joaquin Basin | 88 | 86 | 93 | 89 | 63 | |||||
| Los Angeles Basin | 21 | 21 | 23 | 21 | 23 | |||||
| Uinta Basin | 1 | — | — | — | — | |||||
| Other Basins | 10 | 11 | 11 | 11 | 6 | |||||
| Total | 120 | 118 | 127 | 121 | 92 | |||||
| NGLs (MBbl/d) | ||||||||||
| San Joaquin Basin | 11 | 11 | 10 | 11 | 11 | |||||
| Other Basins | — | — | 1 | — | — | |||||
| Total | 11 | 11 | 11 | 11 | 11 | |||||
| Natural Gas (MMcf/d) | ||||||||||
| San Joaquin Basin | 130 | 133 | 135 | 133 | 131 | |||||
| Los Angeles Basin | 6 | 6 | 6 | 6 | 7 | |||||
| Sacramento Basin | 14 | 14 | 17 | 14 | 17 | |||||
| Uinta Basin | 1 | — | — | — | — | |||||
| Other Basins | 4 | 4 | 3 | 3 | 2 | |||||
| Total | 155 | 157 | 161 | 156 | 157 | |||||
| Total Gross Production (MBoe/d) | 157 | 155 | 165 | 158 | 129 | |||||
|
Attachment 5 | ||||||||||||||||||||
| PRICE STATISTICS | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| 2025 | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||
| Oil ($ per Bbl) | ||||||||||||||||||||
| Realized price with derivative settlements | $ | 64.27 | $ | 67.04 | $ | 73.00 | $ | 67.51 | $ | 75.66 | ||||||||||
| Realized price without derivative settlements | $ | 61.14 | $ | 66.32 | $ | 72.82 | $ | 66.52 | $ | 76.92 | ||||||||||
| NGLs ($/Bbl) | $ | 42.86 | $ | 41.04 | $ | 52.62 | $ | 45.30 | $ | 48.93 | ||||||||||
| Natural gas ($/Mcf) | ||||||||||||||||||||
| Realized price with derivative settlements | $ | 3.91 | $ | 3.47 | $ | 3.65 | $ | 3.57 | $ | 2.99 | ||||||||||
| Realized price without derivative settlements | $ | 3.91 | $ | 3.47 | $ | 3.65 | $ | 3.57 | $ | 2.99 | ||||||||||
| Index Prices | ||||||||||||||||||||
| Brent oil ($/Bbl) | $ | 63.08 | $ | 68.13 | $ | 73.97 | $ | 68.22 | $ | 79.84 | ||||||||||
| WTI oil ($/Bbl) | $ | 59.14 | $ | 64.93 | $ | 70.27 | $ | 64.81 | $ | 75.72 | ||||||||||
| NYMEX average monthly settled price ($/MMBtu) | $ | 3.55 | $ | 3.07 | $ | 2.79 | $ | 3.43 | $ | 2.27 | ||||||||||
| Realized Prices as Percentage of Index Prices | ||||||||||||||||||||
| Oil with derivative settlements as a percentage of Brent | 102 | % | 98 | % | 99 | % | 99 | % | 95 | % | ||||||||||
| Oil without derivative settlements as a percentage of Brent | 97 | % | 97 | % | 98 | % | 98 | % | 96 | % | ||||||||||
| Oil with derivative settlements as a percentage of WTI | 109 | % | 103 | % | 104 | % | 104 | % | 100 | % | ||||||||||
| Oil without derivative settlements as a percentage of WTI | 103 | % | 102 | % | 104 | % | 103 | % | 102 | % | ||||||||||
| NGLs as a percentage of Brent | 68 | % | 60 | % | 71 | % | 66 | % | 61 | % | ||||||||||
| NGLs as a percentage of WTI | 72 | % | 63 | % | 75 | % | 70 | % | 65 | % | ||||||||||
| Natural gas with derivative settlements as a percentage of NYMEX contract month average | 110 | % | 113 | % | 131 | % | 104 | % | 132 | % | ||||||||||
| Natural gas without derivative settlements as a percentage of NYMEX contract month average | 110 | % | 113 | % | 131 | % | 104 | % | 132 | % | ||||||||||
|
Attachment 6 | ||||||||||
| FOURTH QUARTER 2025 DRILLING ACTIVITY | ||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | |||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | |||||
| Development Wells | ||||||||||
| Primary | 3 | — | — | — | 3 | |||||
| Waterflood | 10 | — | — | — | 10 | |||||
| Steamflood | 18 | — | — | — | 18 | |||||
| Total(1) | 31 | — | — | — | 31 | |||||
| TOTAL YEAR 2025 DRILLING ACTIVITY | ||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | |||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | |||||
| Development Wells | ||||||||||
| Primary | 9 | — | — | — | 9 | |||||
| Waterflood | 37 | — | — | — | 37 | |||||
| Steamflood | 30 | — | — | — | 30 | |||||
| Total(1) | 76 | — | — | — | 76 | |||||
| (1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | ||||||||||
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