California Resources Reports Fourth Quarter and Full Year 2024 Financial and Operating Results
Achieves Meaningful Capital Efficiency Improvements and Significant Cost Reductions Following Aera Merger
/EIN News/ -- LONG BEACH, Calif., March 03, 2025 (GLOBE NEWSWIRE) -- California Resources Corporation (NYSE: CRC) today reported financial and operating results for the fourth quarter and full year 2024, as well as its guidance for 2025. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Monday, March 3, 2025. Participation details can be found within this release. Supplemental slides are available on CRC’s website at www.crc.com.
Fourth Quarter 2024 Highlights
- Generated $206 million of net cash flow provided by operating activities, $258 million of operating cash flow before changes in operating assets and liabilities¹ and $118 million in free cash flow¹
- Reported net income of $33 million, adjusted net income¹ of $84 million and adjusted EBITDAX¹ of $316 million
- Delivered average net production of 141 thousand barrels of oil equivalent per day (MBoe/d) (79% oil); exited 2024 with 163 MBoe/d of gross production
- Returned $92 million to shareholders (~78% of fourth quarter free cash flow¹) via share repurchases and dividends2
- Received California’s first Environmental Protection Agency (EPA) Class VI well permits for underground carbon dioxide (CO2) injection and storage into the 26R reservoir. See Carbon TerraVault’s 2024 Update for additional information
Full Year 2024 Highlights
- Transformed and scaled the business through successful Aera merger, and achieved more than 70% of its targeted $235 million in merger-related synergies
- Generated net cash flow provided by operating activities of $610 million, $707 million before changes in operating assets and liabilities1 and $355 million in free cash flow¹
- Posted net income of $376 million, adjusted net income¹ of $317 million and adjusted EBITDAX¹ of $1,006 million
- Delivered average net production of 110 MBoe/d (73% oil)
- Enhanced capital efficiency after deploying $123 million of drilling, completions and workover capital to achieve an entry-to-exit gross production decline of approximately 6%
- Returned $303 million to shareholders (approximately 85% of free cash flow¹) via share repurchases and dividends2
- Exited 2024 with $354 million in available cash3, $983 million in available borrowing capacity and liquidity1 of $1,337 million3
- Sold 0.9 acre Fort Apache real estate property in Huntington Beach for approximately $10 million
- Signed new CO2 management agreements4 (CDMA) and memoranda of understanding4 (MOU) to sequester up to 5.4 million metric tons per annum (MMTPA) of CO2 emissions with reputable national partners and approved California’s first carbon capture and storage (CCS) project. See Carbon TerraVault’s 2024 Update for additional information
2025 Outlook and Highlights
- Capital investments expected to range between $285 - $335 million, including drilling, completions and workover capital of $165 - $180 million and carbon management capital of $20 - $30 million
- Net production expected to be 132 - 138 MBoe/d (79% oil), with an expected range between 5% – 8% entry-to-exit gross production decline
- On track to achieve the remaining $65 million in Aera-related synergies by year-end
- Redeemed $123 million of 2026 Senior Notes at par in February 2025 with the remaining balance of $122 million slated for redemption later this year
- Announced a new up to 1.0 MMTPA of CO2 emissions brownfield MOU4 with National Cement Company of California Inc. (National Cement); Targeting first CO₂ sequestration and cash flow from CCS project at Elk Hills Cryogenic Gas Plant. See Carbon TerraVault and National Cement Sign MOU for California’s First Net Zero Cement Facility for additional information
“We delivered exceptional results in 2024, while successfully completing our transformative merger with Aera Energy. We proved our ability to seamlessly integrate assets and drive synergies. Today, we have the right people, portfolio, and business plan to help lead California’s decarbonization efforts,” said CRC President and CEO Francisco Leon. “In 2025, we are focused on delivering value through our integrated asset portfolio, combining conventional oil and gas, carbon management and an expanding power solutions business. We will maintain financial strength to generate sustainable cash flow, while returning significant capital through dividends and opportunistic share buybacks to our shareholders.”
Fourth Quarter and Full Year 2024 Financial Results
| Selected Production, Price Information and Results of Operations | 4th Quarter | 3rd Quarter | Total Year | Total Year | ||||||||||||
| ($ in millions) | 2024 | 2024 | 2024 | 2023 | ||||||||||||
| Net oil production per day (MBbl/d) | 112 | 113 | 80 | 52 | ||||||||||||
| Realized oil price with derivative settlements ($ per Bbl) | $ | 73.00 | $ | 75.38 | $ | 75.66 | $ | 65.97 | ||||||||
| Net NGL production per day (MBbl/d) | 10 | 11 | 10 | 11 | ||||||||||||
| Realized NGL price ($ per Bbl) | $ | 52.62 | $ | 45.77 | $ | 48.93 | $ | 48.94 | ||||||||
| Net natural gas production per day (MMcf/d) | 115 | 126 | 117 | 135 | ||||||||||||
| Realized natural gas price with derivative settlements ($ per Mcf) | $ | 3.65 | $ | 2.68 | $ | 2.99 | $ | 8.59 | ||||||||
| Net total production per day (MBoe/d) | 141 | 145 | 110 | 86 | ||||||||||||
| Margin from purchased commodities5 ($ millions) | $ | 6 | $ | 8 | $ | 42 | $ | 183 | ||||||||
| Electricity margin6 ($ millions) | $ | 30 | $ | 60 | $ | 119 | $ | 108 | ||||||||
| Net gain from commodity derivatives ($ millions) | $ | (49 | ) | $ | 356 | $ | 241 | $ | (12 | ) | ||||||
| Selected Financial Statement Data and non-GAAP measures: | 4th Quarter | 3rd Quarter | Total Year | Total Year | ||||||||||||||
| ($ and shares in millions, except per share amounts) | 2024 | 2024 | 2024 | 2023 | ||||||||||||||
| Statements of Operations: | ||||||||||||||||||
| Revenues | ||||||||||||||||||
| Total operating revenues | $ | 877 | $ | 1,353 | $ | 3,198 | $ | 2,801 | ||||||||||
| Selected Expenses | ||||||||||||||||||
| Operating costs | $ | 323 | $ | 311 | $ | 966 | $ | 822 | ||||||||||
| General and administrative expenses | $ | 95 | $ | 106 | $ | 321 | $ | 267 | ||||||||||
| Adjusted general and administrative expenses1 | $ | 85 | $ | 89 | $ | 279 | $ | 218 | ||||||||||
| Taxes other than on income | $ | 80 | $ | 85 | $ | 242 | $ | 165 | ||||||||||
| Transportation costs | $ | 21 | $ | 23 | $ | 81 | $ | 67 | ||||||||||
| Operating Income | $ | 68 | $ | 518 | $ | 620 | $ | 808 | ||||||||||
| Interest and debt expense | $ | (28 | ) | $ | (29 | ) | $ | (87 | ) | $ | (56 | ) | ||||||
| Income tax (provision) benefit | $ | (8 | ) | $ | (138 | ) | $ | (140 | ) | $ | (184 | ) | ||||||
| Net income | $ | 33 | $ | 345 | $ | 376 | $ | 564 | ||||||||||
| EPS, Non-GAAP Measures and Select Balance Sheet Data | ||||||||||||||||||
| Adjusted net income1 | $ | 84 | $ | 137 | $ | 317 | $ | 372 | ||||||||||
| Weighted-average common shares outstanding - diluted | 92.2 | 91.2 | 81.4 | 72.5 | ||||||||||||||
| Net income per share - diluted | $ | 0.36 | $ | 3.78 | $ | 4.62 | $ | 7.78 | ||||||||||
| Adjusted net income1 per share - diluted | $ | 0.91 | $ | 1.50 | $ | 3.89 | $ | 5.13 | ||||||||||
| Adjusted EBITDAX1 | $ | 316 | $ | 402 | $ | 1,006 | $ | 862 | ||||||||||
| Net cash provided by operating activities | $ | 206 | $ | 220 | $ | 610 | $ | 653 | ||||||||||
| Net cash provided by operating activities before changes in operating assets and liabilities, net1 | $ | 258 | $ | 249 | $ | 707 | $ | 647 | ||||||||||
| Capital investments | $ | 88 | $ | 79 | $ | 255 | $ | 185 | ||||||||||
| Free cash flow1 | $ | 118 | $ | 141 | $ | 355 | $ | 468 | ||||||||||
| Cash and cash equivalents | $ | 372 | $ | 1,031 | $ | 372 | $ | 496 | ||||||||||
2024 Proved Reserves
As of December 31, 2024, CRC’s total proved reserves were 545 million Boe (MMBoe), of which approximately 81% was oil and 506 MMBoe was proved developed. CRC added 236 MMBoe of proved reserves related to the Aera merger in 2024. Estimated future net cash flows had a PV-101 value of $8,877 million based on SEC pricing of Brent spot price of $80.42 per barrel of oil and NYMEX gas price of $2.13 per MMBtu for natural gas. See Attachment 3 for complete information on CRC’s Non-GAAP Financial Measures and Reconciliations.
2025 Guidance
The following table provides key first quarter and full year 2025 financial and operating guidance. CRC expects to run a one rig program in the first half of 2025, increasing to two rigs in the second half of 2025. See Attachment 2 for complete information on CRC’s first quarter and full year 2025 guidance.
| CRC Guidance7 | 1Q25E |
Total Year 2025E |
| Net Production (MBoe/d) | 138 - 142 | 132 - 138 |
| Net Oil Production (%) | ~79% | ~79% |
| Capital ($ millions) | $60 - $70 | $285 - $335 |
| Adjusted EBITDAX1 ($ millions) | $275 - $295 | $1,100 - $1,200 |
Shareholder Returns and Dividend Announcements
CRC is committed to sustainably returning cash to shareholders through dividends and repurchases of its outstanding common stock. Since mid-2021, the Company has returned approximately $1,060 million to shareholders2, including $793 million in share repurchases and $267 million in dividends.
In 2024, CRC repurchased 3.6 million shares of its common stock for $190 million2 at an average price of $52.12 per share and returned $113 million to shareholders in dividends. As of December 31, 2024, CRC had approximately $557 million of capacity remaining under its share repurchase authorization.
On March 2, 2025, CRC’s Board of Directors declared a quarterly cash dividend of $0.3875 per share of common stock, payable to shareholders of record on March 10, 2025. The dividend is expected to be paid on March 21, 2025.
Balance Sheet and Liquidity
In November 2024, CRC reaffirmed its $1,500 million borrowing base under its Revolving Credit Facility (the Facility), extended its maturity date to March 16, 2029, amended the springing maturity to allow the 2026 Senior Notes to remain outstanding past October 31, 2025 subject to certain conditions, and increased elected commitments by $50 million, as well as other technical amendments.
At year-end 2024, CRC had $354 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 of $1,337 million3.
2024 Sustainability Highlights
“In 2024, CRC demonstrated its unwavering commitment to sustainability by achieving significant milestones in environmental stewardship, safety, and community engagement,” said Leon. “We are proud that our assets in the Los Angeles Basin were MiQ 'Grade A' certified, and we plan to continue investing in the Kern County community through our Community Benefits Plan. These are just two examples of our dedication to the communities and areas where we live and work.”
- Achieved a 'Grade A' certification from MiQ for methane emissions performance in the Los Angeles Basin, marking the first such certification for oil and gas operations in California and the Rocky Mountain region.
- Eliminated 311 gas venting pneumatics, aligning with 2030 methane reduction goals and demonstrating a proactive approach to minimizing environmental impact by reducing methane emissions by over 260 metric tons per year.
- Delivered more than 112 million barrels of water for agricultural use, exceeding internal consumption and supporting local agriculture.
- Launched the Carbon TerraVault I Elk Hills Community Benefits Plan, committing 1% of each project investment toward programs and partnerships that provide transformative benefits to local communities in Kern County.
Upcoming Investor Conference Participation
CRC will be participating in the following events in March 2025:
- DEP THRIVE Energy Conference on March 5 in Houston, TX
- Morgan Stanley Global Energy & Power Conference on March 6 in New York, NY
- CERAWeek 2025 on March 10 to 12 in Houston, TX
- 37th Annual ROTH Conference on March 17 in Dana Point, CA
- 2025 NYSE Investor Access Day on March 20, Virtual
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 3, 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/10194600/fe015c8aa0. 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 (excluding effects of PSCs), adjusted net income (loss), adjusted net income (loss) per share - basic and diluted, net cash provided by operating activities before changes in operating assets and liabilities, net, adjusted EBITDAX, free cash flow, adjusted general and administrative expenses and capital efficiency including reconciliations to their most directly comparable GAAP measure, where applicable. See Attachment 2 for the 1Q25 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 The total value of shares purchased includes approximately $2 million and $1 million in both the years ended December 31, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning in 2023. Commissions paid were not significant in all periods presented.
3 Excludes restricted cash of $18 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 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.
6 Electricity margin is calculated as the difference between electricity sales and electricity generation expenses.
7 1Q25 guidance assumes Brent price of $76.54 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.38 per mcf. Total year 2025 guidance assumes Brent price of $73.05 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.49 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. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. Additionally, the information in this report contains forward-looking statements related to the recently announced Aera merger.
Although CRC believes the expectations and forecasts reflected in its forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond its control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause CRC’s actual results to be materially different than those expressed in its forward-looking statements include:
- fluctuations in commodity prices, including supply and demand considerations for CRC’s products and services, and the impact of such fluctuations on revenues and operating expenses;
- decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods;
- government policy, war and political conditions and events, including the military conflicts in Israel, Lebanon, Ukraine and the Middle East;
- the ability to successfully execute integration efforts in connection with the Aera Merger, and achieve projected synergies and ensure that such synergies are sustainable;
- regulatory actions and changes that affect the oil and gas industry generally and us in particular, including (1) the availability or timing of, or conditions imposed on, EPA and other governmental permits and approvals necessary for drilling or development activities or its carbon management segment; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of its products;
- the efforts of activists to delay prevent oil and gas activities or the development of CRC’s carbon management segment through a variety of tactics, including litigation;
- the impact of inflation on future expenses and changes generally in the prices of goods and services;
- changes in business strategy and capital plan;
- lower-than-expected production or higher-than-expected production decline rates;
- changes to estimates of reserves and related future cash flows, including changes arising from CRC’s inability to develop such reserves in a timely manner, and any inability to replace such reserves;
- the recoverability of resources and unexpected geologic conditions;
- general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets;
- production-sharing contracts' effects on production and operating costs;
- the lack of available equipment, service or labor price inflation;
- limitations on transportation or storage capacity and the need to shut-in wells;
- any failure of risk management;
- results from operations and competition in the industries in which it operates;
- CRC’s ability to realize the anticipated benefits from prior or future efforts to reduce costs;
- environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions);
- the creditworthiness and performance of its counterparties, including financial institutions, operating partners, CCS project participants and other parties;
- reorganization or restructuring of its operations;
- CRC’s ability to claim and utilize tax credits or other incentives in connection with our CCS projects;
- CRC’s ability to realize the benefits contemplated by its energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;
- CRC’s ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and its ability to convert CDMAs to definitive agreements and enter into other offtake agreements;
- CRC’s ability to maximize the value of its carbon management segment and operate it on a stand alone basis;
- CRC’s ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;
- uncertainty around the accounting of emissions and its ability to successfully gather and verify emissions data and other environmental impacts;
- changes to CRC’s dividend policy and share repurchase program, and its ability to declare future dividends or repurchase shares under its debt agreements;
- limitations on CRC’s financial flexibility due to existing and future debt;
- insufficient cash flow to fund its capital plan and other planned investments and return capital to shareholders;
- changes in interest rates;
- CRC’s access to and the terms of credit in commercial banking and capital markets, including its ability to refinance debt or obtain separate financing for its carbon management segment;
- changes in state, federal or international tax rates, including CRC’s ability to utilize its net operating loss carryforwards to reduce its income tax obligations;
- effects of hedging transactions;
- the effect of CRC’s stock price on costs associated with incentive compensation;
- inability to enter into desirable transactions, including joint ventures, divestitures of oil and natural gas properties and real estate, and acquisitions, and its ability to achieve any expected synergies;
- disruptions due to earthquakes, forest fires, floods, extreme weather events or other natural occurrences, accidents, mechanical failures, power outages, transportation or storage constraints, labor difficulties, cybersecurity breaches or attacks or other catastrophic events;
- pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19 pandemic; and
- other factors discussed in Part I, Item 1A – Risk Factors.
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 | |||||||||||||||||||
| ($ and shares in millions, except per share amounts) | 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||
| 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||
| Statements of Operations: | |||||||||||||||||||
| Revenues | |||||||||||||||||||
| Oil, natural gas and NGL sales | $ | 826 | $ | 870 | $ | 483 | $ | 2,537 | $ | 2,155 | |||||||||
| Net (loss) gain from commodity derivatives | (49 | ) | 356 | 119 | 24 | (12 | ) | ||||||||||||
| Revenue from marketing of purchased commodities | 59 | 51 | 71 | 235 | 407 | ||||||||||||||
| Electricity sales | 39 | 69 | 42 | 159 | 211 | ||||||||||||||
| Interest and other revenue | 2 | 7 | 11 | 26 | 40 | ||||||||||||||
| Total operating revenues | 877 | 1,353 | 726 | 3,198 | 2,801 | ||||||||||||||
| Operating Expenses | |||||||||||||||||||
| Operating costs | 323 | 311 | 186 | 966 | 822 | ||||||||||||||
| General and administrative expenses | 95 | 106 | 66 | 321 | 267 | ||||||||||||||
| Depreciation, depletion and amortization | 142 | 140 | 55 | 388 | 225 | ||||||||||||||
| Asset impairment | 1 | — | — | 14 | 3 | ||||||||||||||
| Taxes other than on income | 80 | 85 | 33 | 242 | 165 | ||||||||||||||
| Costs related to marketing of purchased commodities | 53 | 43 | 42 | 193 | 224 | ||||||||||||||
| Electricity generation expenses | 9 | 9 | 18 | 40 | 103 | ||||||||||||||
| Transportation costs | 21 | 23 | 18 | 81 | 67 | ||||||||||||||
| Accretion expense | 31 | 31 | 11 | 87 | 46 | ||||||||||||||
| Net loss on natural gas purchase derivatives | 19 | 9 | 8 | 30 | 8 | ||||||||||||||
| Carbon management business expenses | 20 | 13 | 17 | 56 | 37 | ||||||||||||||
| Measurement period adjustments | (12 | ) | — | — | (12 | ) | — | ||||||||||||
| Other operating expenses, net | 31 | 65 | 14 | 183 | 58 | ||||||||||||||
| Total operating expenses | 813 | 835 | 468 | 2,589 | 2,025 | ||||||||||||||
| Net gain on asset divestitures | 4 | — | 25 | 11 | 32 | ||||||||||||||
| Operating Income | 68 | 518 | 283 | 620 | 808 | ||||||||||||||
| Non-Operating (Expenses) Income | |||||||||||||||||||
| Interest and debt expense | (28 | ) | (29 | ) | (13 | ) | (87 | ) | (56 | ) | |||||||||
| Loss from investment in unconsolidated subsidiaries | (1 | ) | (2 | ) | (3 | ) | (10 | ) | (9 | ) | |||||||||
| Loss on early extinguishment of debt | — | (5 | ) | (1 | ) | (5 | ) | (1 | ) | ||||||||||
| Other non-operating income (loss), net | 2 | 1 | 1 | (2 | ) | 6 | |||||||||||||
| Income Before Income Taxes | 41 | 483 | 267 | 516 | 748 | ||||||||||||||
| Income tax (provision) | (8 | ) | (138 | ) | (79 | ) | (140 | ) | (184 | ) | |||||||||
| Net Income | $ | 33 | $ | 345 | $ | 188 | $ | 376 | $ | 564 | |||||||||
| Net income per share - basic | $ | 0.36 | $ | 3.86 | $ | 2.74 | $ | 4.74 | $ | 8.10 | |||||||||
| Net income per share - diluted | $ | 0.36 | $ | 3.78 | $ | 2.60 | $ | 4.62 | $ | 7.78 | |||||||||
| Adjusted net income | $ | 84 | $ | 137 | $ | 67 | $ | 317 | $ | 372 | |||||||||
| Adjusted net income per share - basic | $ | 0.93 | $ | 1.53 | $ | 0.98 | $ | 4.00 | $ | 5.34 | |||||||||
| Adjusted net income per share - diluted | $ | 0.91 | $ | 1.50 | $ | 0.93 | $ | 3.89 | $ | 5.13 | |||||||||
| Weighted-average common shares outstanding - basic | 90.8 | 89.4 | 68.7 | 79.3 | 69.6 | ||||||||||||||
| Weighted-average common shares outstanding - diluted | 92.2 | 91.2 | 72.3 | 81.4 | 72.5 | ||||||||||||||
| Adjusted EBITDAX | $ | 316 | $ | 402 | $ | 179 | $ | 1,006 | $ | 862 | |||||||||
| Effective tax rate | 20 | % | 29 | % | 30 | % | 27 | % | 25 | % | |||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | |||||||||||||||
| ($ in millions) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||
| Cash Flow Data: | |||||||||||||||||||
| Net cash provided by operating activities | $ | 206 | $ | 220 | $ | 131 | $ | 610 | $ | 653 | |||||||||
| Net cash used in investing activities | $ | (67 | ) | $ | (928 | ) | $ | (42 | ) | $ | (1,077 | ) | $ | (175 | ) | ||||
| Net cash (used) provided by financing activities | $ | (8 | ) | $ | (82 | ) | $ | (72 | ) | $ | 343 | $ | (289 | ) | |||||
| December 31, | December 31, | ||||||||||||||||||
| ($ in millions) | 2024 | 2023 | |||||||||||||||||
| Selected Balance Sheet Data: | |||||||||||||||||||
| Total current assets | $ | 1,024 | $ | 929 | |||||||||||||||
| Property, plant and equipment, net | $ | 5,680 | $ | 2,770 | |||||||||||||||
| Deferred tax asset | $ | 73 | $ | 132 | |||||||||||||||
| Total current liabilities | $ | 980 | $ | 616 | |||||||||||||||
| Long-term debt, net | $ | 1,132 | $ | 540 | |||||||||||||||
| Noncurrent asset retirement obligations | $ | 995 | $ | 422 | |||||||||||||||
| Deferred tax liability | $ | 113 | $ | — | |||||||||||||||
| Total stockholders' equity | $ | 3,538 | $ | 2,219 | |||||||||||||||
| GAINS AND LOSSES FROM COMMODITY DERIVATIVES | |||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | |||||||||||||||
| ($ millions) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||
| Non-cash derivative (loss) gain | $ | (51 | ) | $ | 373 | $ | 160 | $ | 274 | $ | 252 | ||||||||
| Net received (paid) on settled commodity derivatives | 2 | (17 | ) | (49 | ) | (33 | ) | (272 | ) | ||||||||||
| Net (loss) gain from commodity derivatives | $ | (49 | ) | $ | 356 | $ | 111 | $ | 241 | $ | (20 | ) | |||||||
| CAPITAL INVESTMENTS | ||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||
| ($ millions) | 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||
| Facilities (1) | $ | 44 | $ | 36 | $ | 20 | $ | 111 | $ | 47 | ||||
| Drilling and completions | 17 | 19 | 16 | 69 | 67 | |||||||||
| Workovers | 17 | 19 | 11 | 54 | 39 | |||||||||
| Total Oil and natural gas capital | 78 | 74 | 47 | 234 | 153 | |||||||||
| CMB (1) | 6 | 4 | 4 | 12 | 5 | |||||||||
| Corporate and other | 4 | 1 | 15 | 9 | 27 | |||||||||
| Total capital program | $ | 88 | $ | 79 | $ | 66 | $ | 255 | $ | 185 | ||||
| (1) Facilities capital includes $1 million in the fourth quarter of 2023, and $4 million for the total year 2023, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business. | ||||||||||||||
| Attachment 2 | |||||||
| CRC GUIDANCE |
Consolidated 1Q25E |
Oil and Natural Gas 1Q25E |
Carbon Management 1Q25E |
||||
| Net Production (MBoe/d) | 138 - 142 | ||||||
| Net Oil Production (%) | ~79% | ||||||
| Operating Costs and CMB Expenses ($ millions) | $335 - $365 | $320 - $340 | $15 - $25 | ||||
| Non-Energy Operating and Gas Processing Costs ($ millions) | $210 - $225 | ||||||
| General and Administrative Expenses ($ millions) | $80 - $84 | $10 - $12 | $2 - $4 | ||||
| Adjusted General and Administrative Expenses ($ millions) | $75 - $80 | $10 - $12 | $2 - $4 | ||||
| Depreciation, Depletion and Amortization ($ millions) | $125 - $130 | $117 - $121 | |||||
| Capital ($ millions) | $60 - $70 | $51 - $55 | $5 - $10 | ||||
| Drilling, completions and workovers ($ millions) | $33 - $35 | $33 - $35 | |||||
| Facilities ($ millions) | $18 - $20 | $18 - $20 | |||||
| Carbon management business ($ millions) | $5 - $10 | $5 - $10 | |||||
| Corporate and other ($ millions) | $4 - $5 | ||||||
| Adjusted EBITDAX ($ millions) | $275 - $295 | $295 - $319 | ($20) - ($24) | ||||
| Margin from Purchased Commodities ($ millions) (1) | $10 - $15 | ||||||
| Electricity Margin ($ millions) (2) | $0 - $5 | ||||||
| Other Operating Revenue and Expenses, net ($ millions)(3) | ($5) - $5 | ||||||
| Transportation Costs ($ millions) | $18 - $22 | $5 - $10 | |||||
| Taxes Other Than on Income ($ millions) | $70 - $78 | $57 - $61 | |||||
| Interest and Debt Expense ($ millions) | $26 - $30 | ||||||
| Other Assumptions: | |||||||
| Brent ($/Bbl) | $76.54 | ||||||
| NYMEX ($/Mcf) | $3.38 | ||||||
| Oil - % of Brent: | 94% to 98% | ||||||
| NGL - % of Brent: | 65% to 69% | ||||||
| Natural Gas - % of NYMEX: | 110% to 115% | ||||||
| Deferred Income Taxes | 38% - 42% | ||||||
| Effective Tax Rate | 29% | ||||||
| CRC GUIDANCE |
Consolidated 2025E |
Oil and Natural Gas 2025E |
Carbon Management 2025E |
|||
| Net Production (MBoe/d) | 132 - 138 | |||||
| Net Oil Production (%) | ~79% | |||||
| Operating Costs and CMB Expenses ($ millions) | $1,325 - $1,425 | $1,265 - $1,335 | $60 - $90 | |||
| Non-Energy Operating and Gas Processing Costs ($ millions) | $825 - $855 | |||||
| General and Administrative Expenses ($ millions) | $325 - $345 | $40 - $45 | $10 - $15 | |||
| Adjusted General and Administrative Expenses ($ millions) | $300 - $320 | $40 - $45 | $10 - $15 | |||
| Depreciation, Depletion and Amortization ($ millions) | $490 - $530 | $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 | $1,187 - $1,296 | ($87) - ($96) | |||
| Margin from Purchased Commodities ($ millions) (1) | $80 - $95 | |||||
| Electricity Margin ($ millions) (2) | $120 - $145 | |||||
| Other Operating Revenue and Expenses, net ($ millions) (3) | ($15) - $10 | |||||
| Transportation Costs ($ millions) | $85 - $92 | $25 - $30 | ||||
| Taxes Other Than on Income ($ millions) | $275 - $300 | $225 - $235 | ||||
| Interest and Debt Expense ($ millions) | $100 - $113 | |||||
| Commodity Assumptions: | ||||||
| Brent ($/Bbl) | $73.05 | |||||
| NYMEX ($/Mcf) | $3.49 | |||||
| Oil - % of Brent: | 94% to 98% | |||||
| NGL - % of Brent: | 60% to 68% | |||||
| Natural Gas - % of NYMEX: | 95% to 105% | |||||
| Deferred Income Taxes | 35% - 45% | |||||
| Effective Tax Rate | 29% | |||||
|
(1) Margin from purchased commodities is calculated as the difference between revenue from marketing of purchased commodities and costs related to marketing of purchased commodities, and excludes costs of transportation. (2) Electricity margin is calculated as the difference between electricity sales and electricity generation expenses. (3) Other operating revenue and expenses, net is calculated as the difference between other revenue and other operating expenses, net and includes exploration expense. See Attachment 3 for management’s disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC’s results of operations and financial condition. | ||||||
| ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES RECONCILIATION | ||||||||||||||||||||||||||
| 1Q25E | ||||||||||||||||||||||||||
| Consolidated | Oil and Natural Gas | Carbon Management | ||||||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | ||||||||||||||||||||
| General and administrative expenses | $ | 80 | $ | 84 | $ | 10 | $ | 12 | $ | 2 | $ | 4 | ||||||||||||||
| Equity-settled stock-based compensation | (4 | ) | (4 | ) | — | — | (1 | ) | (1 | ) | ||||||||||||||||
| Other | (1 | ) | — | — | — | — | — | |||||||||||||||||||
| Estimated adjusted general and administrative expenses | $ | 75 | $ | 80 | $ | 10 | $ | 12 | $ | 1 | $ | 3 | ||||||||||||||
| Total Year 2025E | ||||||||||||||||||||||||||
| Consolidated | Oil and Natural Gas | Carbon Management | ||||||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | ||||||||||||||||||||
| General and administrative expenses | $ | 325 | $ | 345 | $ | 40 | $ | 45 | $ | 10 | $ | 15 | ||||||||||||||
| Equity-settled stock-based compensation | (23 | ) | (23 | ) | — | — | (5 | ) | (5 | ) | ||||||||||||||||
| Other | (2 | ) | (2 | ) | — | — | — | — | ||||||||||||||||||
| Estimated adjusted general and administrative expenses | $ | 300 | $ | 320 | $ | 40 | $ | 45 | $ | 5 | $ | 10 | ||||||||||||||
| ESTIMATED ADJUSTED EBITDAX RECONCILIATION | |||||||||||||
| Consolidated | |||||||||||||
| 1Q25E | 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 | 125 | 130 | 480 | 520 | |||||||||
| Income taxes | 27 | 30 | 86 | 96 | |||||||||
| Unusual, infrequent and other items | (14 | ) | (22 | ) | 13 | 32 | |||||||
| Other non-cash items | |||||||||||||
| Accretion expense | 30 | 31 | 120 | 124 | |||||||||
| Stock-settled compensation | 4 | 4 | 23 | 23 | |||||||||
| 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 | — | — | 66 | 76 | |||||||||
| Working capital changes | 152 | 151 | 188 | 252 | |||||||||
| Estimated adjusted EBITDAX | $ | 275 | $ | 295 | $ | 1,100 | $ | 1,200 | |||||
| Oil and Natural Gas | |||||||||||||||
| 1Q25E | 2025E | ||||||||||||||
| ($ millions) | Low | High | Low | High | |||||||||||
| Segment profit | $ | 246 | $ | 265 | $ | 795 | $ | 815 | |||||||
| Depreciation, depletion and amortization | 117 | 121 | 460 | 475 | |||||||||||
| Unusual, infrequent and other items | (96 | ) | (100 | ) | (183 | ) | (119 | ) | |||||||
| Other non-cash items | |||||||||||||||
| Accretion expense | 29 | 33 | 115 | 125 | |||||||||||
| Estimated adjusted EBITDAX | $ | 295 | $ | 319 | $ | 1,187 | $ | 1,296 | |||||||
| Net cash provided by operating activities | $ | 340 | $ | 365 | $ | 1,247 | $ | 1,267 | |||||||
| Working capital changes | (45 | ) | (46 | ) | (60 | ) | 29 | ||||||||
| Estimated adjusted EBITDAX | $ | 295 | $ | 319 | $ | 1,187 | $ | 1,296 | |||||||
| Carbon Management | |||||||||||||||
| 1Q25E | 2025E | ||||||||||||||
| ($ millions) | Low | High | Low | High | |||||||||||
| Segment loss | $ | (25 | ) | $ | (30 | ) | $ | (103 | ) | $ | (113 | ) | |||
| Interest and debt expense, net | 3 | 4 | 11 | 12 | |||||||||||
| Other non-cash items | |||||||||||||||
| Stock-settled compensation | 2 | 2 | 5 | 5 | |||||||||||
| Estimated adjusted EBITDAX | $ | (20 | ) | $ | (24 | ) | $ | (87 | ) | $ | (96 | ) | |||
| Net cash provided by operating activities | $ | (21 | ) | $ | (26 | ) | $ | (92 | ) | $ | (102 | ) | |||
| Working capital changes | 1 | 2 | 5 | 6 | |||||||||||
| Estimated adjusted EBITDAX | $ | (20 | ) | $ | (24 | ) | $ | (87 | ) | $ | (96 | ) | |||
| 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 changes in operating assets and liabilities, net, 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. | |||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | |||||||||||||||
| ($ millions, except per share amounts) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||
| Net income | $ | 33 | $ | 345 | $ | 188 | $ | 376 | $ | 564 | |||||||||
| Unusual, infrequent and other items: | |||||||||||||||||||
| Non-cash derivative loss (gain) | 51 | (373 | ) | (160 | ) | (274 | ) | (252 | ) | ||||||||||
| Asset impairment | 1 | — | — | 14 | 3 | ||||||||||||||
| Severance and termination costs | 2 | 27 | — | 30 | 10 | ||||||||||||||
| Aera merger related costs | 1 | 30 | — | 57 | — | ||||||||||||||
| Increased power and fuel costs due to power plant maintenance | 6 | 8 | — | 50 | — | ||||||||||||||
| Net gain on asset divestitures | (4 | ) | — | (25 | ) | (11 | ) | (32 | ) | ||||||||||
| Loss on early extinguishment of debt | — | 5 | 1 | 5 | 1 | ||||||||||||||
| Other, net | 13 | 6 | 16 | 38 | 46 | ||||||||||||||
| Total unusual, infrequent and other items | 70 | (297 | ) | (168 | ) | (91 | ) | (224 | ) | ||||||||||
| Income tax (benefit) provision of adjustments at effective tax rate | (19 | ) | 89 | 47 | 32 | 63 | |||||||||||||
| Income tax benefit - out of period | — | — | — | — | (31 | ) | |||||||||||||
| Adjusted net income | $ | 84 | $ | 137 | $ | 67 | $ | 317 | $ | 372 | |||||||||
| Net income per share - basic | $ | 0.36 | $ | 3.86 | $ | 2.74 | $ | 4.74 | $ | 8.10 | |||||||||
| Net income per share - diluted | $ | 0.36 | $ | 3.78 | $ | 2.60 | $ | 4.62 | $ | 7.78 | |||||||||
| Adjusted net income per share - basic | $ | 0.93 | $ | 1.53 | $ | 0.98 | $ | 4.00 | $ | 5.34 | |||||||||
| Adjusted net income per share - diluted | $ | 0.91 | $ | 1.50 | $ | 0.93 | $ | 3.89 | $ | 5.13 | |||||||||
| 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. | |||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | |||||||||||||||
| ($ millions, except per BOE amounts) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||
| Net income | $ | 33 | $ | 345 | $ | 188 | $ | 376 | $ | 564 | |||||||||
| Interest and debt expense | 28 | 29 | 13 | 87 | 56 | ||||||||||||||
| Depreciation, depletion and amortization | 142 | 140 | 55 | 388 | 225 | ||||||||||||||
| Income tax provision | 8 | 138 | 79 | 140 | 184 | ||||||||||||||
| Exploration expense | — | 1 | 1 | 2 | 3 | ||||||||||||||
| Interest income | (4 | ) | (1 | ) | (7 | ) | (19 | ) | (21 | ) | |||||||||
| Unusual, infrequent and other items (1) | 70 | (297 | ) | (168 | ) | (91 | ) | (224 | ) | ||||||||||
| Non-cash items | |||||||||||||||||||
| Accretion expense | 31 | 31 | 11 | 87 | 46 | ||||||||||||||
| Stock-based compensation | 6 | 6 | 6 | 23 | 27 | ||||||||||||||
| Taxes related to acquisition accounting | 2 | 10 | — | 12 | — | ||||||||||||||
| Pension and post-retirement benefits | — | — | 1 | 1 | 2 | ||||||||||||||
| Adjusted EBITDAX | $ | 316 | $ | 402 | $ | 179 | $ | 1,006 | $ | 862 | |||||||||
| Net cash provided by operating activities | $ | 206 | $ | 220 | $ | 131 | $ | 610 | $ | 653 | |||||||||
| Cash interest payments | 42 | 24 | 1 | 88 | 49 | ||||||||||||||
| Cash interest received | (4 | ) | (1 | ) | (7 | ) | (19 | ) | (21 | ) | |||||||||
| Cash income taxes | 50 | 29 | 41 | 105 | 121 | ||||||||||||||
| Exploration expenditures | — | 1 | 1 | 2 | 3 | ||||||||||||||
| Adjustments to working capital changes | 22 | 129 | 12 | 220 | 57 | ||||||||||||||
| Adjusted EBITDAX | $ | 316 | $ | 402 | $ | 179 | $ | 1,006 | $ | 862 | |||||||||
| Adjusted EBITDAX per Boe | $ | 24.35 | $ | 30.19 | $ | 23.57 | $ | 25.09 | $ | 27.51 | |||||||||
| (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 16 Segment Information in CRC’s 2024 Annual Report. | |||||||||||||||||||
| Oil & Natural Gas Segment | 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||
| ($ millions, except per BOE amounts) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||
| Segment profit | $ | 273 | $ | 305 | $ | 223 | $ | 815 | $ | 922 | |||||||||
| Depreciation, depletion and amortization | 125 | 126 | 46 | 354 | 205 | ||||||||||||||
| Exploration expense | — | — | — | 2 | 3 | ||||||||||||||
| Accretion expense | 31 | 31 | 11 | 87 | 46 | ||||||||||||||
| Adjusted income items | (3 | ) | 15 | (22 | ) | 54 | (30 | ) | |||||||||||
| Adjusted EBITDAX - Oil and Natural Gas | $ | 426 | $ | 477 | $ | 258 | $ | 1,312 | $ | 1,146 | |||||||||
| Carbon Management Segment | |||||||||||||||||||
| Segment loss | $ | (30 | ) | $ | (25 | ) | $ | (22 | ) | $ | (94 | ) | $ | (66 | ) | ||||
| Interest on contingent liability (related to Carbon TerraVault JV) | 3 | 3 | 1 | 9 | 5 | ||||||||||||||
| Loss from investment in unconsolidated subsidiaries | 1 | 3 | — | 5 | — | ||||||||||||||
| Adjusted EBITDAX - Carbon Management | $ | (26 | ) | $ | (19 | ) | $ | (21 | ) | $ | (80 | ) | $ | (61 | ) | ||||
| 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 changes in operating assets and liabilities, net, 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. | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ millions) | 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||
| Net cash provided by operating activities before changes in operating assets and liabilities, net | $ | 258 | $ | 249 | $ | 104 | $ | 707 | $ | 647 | ||||||||||
| Changes in operating assets and liabilities, net | (52 | ) | (29 | ) | 27 | (97 | ) | 6 | ||||||||||||
| Net cash provided by operating activities | 206 | 220 | 131 | 610 | 653 | |||||||||||||||
| Capital investments | (88 | ) | (79 | ) | (66 | ) | (255 | ) | (185 | ) | ||||||||||
| Free cash flow | $ | 118 | $ | 141 | $ | 65 | $ | 355 | $ | 468 | ||||||||||
| Add: Aera merger related costs | 1 | 30 | — | 57 | — | |||||||||||||||
| Free cash flow after special items | $ | 119 | $ | 171 | $ | 65 | $ | 412 | $ | 468 | ||||||||||
| 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) | 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||
| General and administrative expenses | $ | 95 | $ | 106 | $ | 66 | $ | 321 | $ | 267 | ||||||||||
| Stock-based compensation | (6 | ) | (6 | ) | (6 | ) | (23 | ) | (27 | ) | ||||||||||
| Information technology infrastructure | — | — | (4 | ) | (3 | ) | (17 | ) | ||||||||||||
| Accelerated vesting | (3 | ) | (9 | ) | — | (12 | ) | — | ||||||||||||
| Retention awards | — | (2 | ) | — | (2 | ) | — | |||||||||||||
| Other | (1 | ) | — | (1 | ) | (2 | ) | (5 | ) | |||||||||||
| Adjusted G&A expenses | $ | 85 | $ | 89 | $ | 55 | $ | 279 | $ | 218 | ||||||||||
| Adjusted G&A per BOE | $ | 6.55 | $ | 6.68 | $ | 7.24 | $ | 6.96 | $ | 6.96 | ||||||||||
| 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. | ||||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||||||||||||
| ($ per BOE) | 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||
| Energy operating costs (1) | $ | 7.70 | $ | 7.29 | $ | 8.65 | $ | 7.38 | $ | 10.31 | ||||||||||
| Gas processing costs (2) | 0.31 | 0.38 | 0.60 | 0.40 | 0.58 | |||||||||||||||
| Non-energy operating costs(3) | 17.34 | 16.06 | 15.24 | 16.73 | 15.35 | |||||||||||||||
| Operating costs | $ | 25.35 | $ | 23.73 | $ | 24.49 | $ | 24.51 | $ | 26.24 | ||||||||||
| Costs attributable to PSCs | ||||||||||||||||||||
| Excess energy operating costs attributable to PSCs | $ | (0.46 | ) | $ | (0.75 | ) | $ | (1.01 | ) | $ | (0.64 | ) | $ | (1.00 | ) | |||||
| Excess non-energy operating costs attributable to PSCs | (0.76 | ) | (0.48 | ) | (1.32 | ) | (1.03 | ) | (1.25 | ) | ||||||||||
| Excess costs attributable to PSCs | $ | (1.22 | ) | $ | (1.23 | ) | $ | (2.33 | ) | $ | (1.67 | ) | $ | (2.25 | ) | |||||
| Energy operating costs, excluding effect of PSCs (1) | $ | 7.24 | $ | 6.54 | $ | 7.64 | $ | 6.74 | $ | 9.31 | ||||||||||
| Gas processing costs, excluding effect of PSCs (2) | 0.31 | 0.38 | 0.60 | 0.40 | 0.58 | |||||||||||||||
| Non-energy operating costs, excluding effect of PSCs (3) | 16.58 | 15.58 | 13.92 | 15.70 | 14.10 | |||||||||||||||
| Operating costs, excluding effects of PSCs | $ | 24.13 | $ | 22.50 | $ | 22.16 | $ | 22.84 | $ | 23.99 | ||||||||||
| (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. | ||||||||||||||||||||
| 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, 2024 | ||
| Standardized Measure | $ | 6,702 | |
| Present value of future income taxes discounted at 10% | 2,175 | ||
| PV-10 of cash flows (*) | $ | 8,877 | |
| (*) 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. | |||
| Attachment 4 | ||||||||||
| PRODUCTION STATISTICS | ||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | ||||||
| Net Production Per Day | 2024 | 2024 | 2023 | 2024 | 2023 | |||||
| Oil (MBbl/d) | ||||||||||
| San Joaquin Basin | 86 | 90 | 32 | 58 | 33 | |||||
| Los Angeles Basin | 17 | 17 | 18 | 17 | 19 | |||||
| Other Basins | 9 | 6 | — | 5 | — | |||||
| Total | 112 | 113 | 50 | 80 | 52 | |||||
| NGLs (MBbl/d) | ||||||||||
| San Joaquin Basin | 10 | 11 | 11 | 10 | 11 | |||||
| Total | 10 | 11 | 11 | 10 | 11 | |||||
| Natural Gas (MMcf/d) | ||||||||||
| San Joaquin Basin | 98 | 111 | 114 | 99 | 119 | |||||
| Los Angeles Basin | 1 | 1 | 1 | 1 | 1 | |||||
| Sacramento Basin | 13 | 13 | 15 | 13 | 15 | |||||
| Other Basins | 3 | 1 | — | 4 | — | |||||
| Total | 115 | 126 | 130 | 117 | 135 | |||||
| Total Net Production (MBoe/d) | 141 | 145 | 83 | 110 | 86 | |||||
| Gross Operated and Net Non-Operated | 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | |||||
| Production Per Day | 2024 | 2024 | 2023 | 2024 | 2023 | |||||
| Oil (MBbl/d) | ||||||||||
| San Joaquin Basin | 93 | 96 | 36 | 63 | 37 | |||||
| Los Angeles Basin | 23 | 23 | 25 | 23 | 25 | |||||
| Other Basins | 11 | 8 | — | 6 | — | |||||
| Total | 127 | 127 | 61 | 92 | 62 | |||||
| NGLs (MBbl/d) | ||||||||||
| San Joaquin Basin | 10 | 11 | 11 | 11 | 12 | |||||
| Other Basins | 1 | — | — | — | — | |||||
| Total | 11 | 11 | 11 | 11 | 12 | |||||
| Natural Gas (MMcf/d) | ||||||||||
| San Joaquin Basin | 135 | 137 | 129 | 131 | 135 | |||||
| Los Angeles Basin | 6 | 7 | 8 | 7 | 7 | |||||
| Sacramento Basin | 17 | 16 | 18 | 17 | 19 | |||||
| Other Basins | 3 | 3 | — | 2 | — | |||||
| Total | 161 | 163 | 155 | 157 | 161 | |||||
| Total Gross Production (MBoe/d) | 165 | 165 | 98 | 129 | 101 | |||||
|
Attachment 5 |
|||||||||||||||||||
| PRICE STATISTICS | |||||||||||||||||||
| 4th Quarter | 3rd Quarter | 4th Quarter | Total Year | Total Year | |||||||||||||||
| 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||
| Oil ($ per Bbl) | |||||||||||||||||||
| Realized price with derivative settlements | $ | 73.00 | $ | 75.38 | $ | 71.34 | $ | 75.66 | $ | 65.97 | |||||||||
| Realized price without derivative settlements | $ | 72.82 | $ | 77.10 | $ | 82.00 | $ | 76.92 | $ | 80.41 | |||||||||
| NGLs ($/Bbl) | $ | 52.62 | $ | 45.77 | $ | 49.08 | $ | 48.93 | $ | 48.94 | |||||||||
| Natural gas ($/Mcf) | |||||||||||||||||||
| Realized price with derivative settlements | $ | 3.65 | $ | 2.68 | $ | 4.66 | $ | 2.99 | $ | 8.59 | |||||||||
| Realized price without derivative settlements | $ | 3.65 | $ | 2.68 | $ | 4.66 | $ | 2.99 | $ | 8.59 | |||||||||
| Index Prices | |||||||||||||||||||
| Brent oil ($/Bbl) | $ | 73.97 | $ | 78.54 | $ | 82.69 | $ | 79.84 | $ | 82.22 | |||||||||
| WTI oil ($/Bbl) | $ | 70.27 | $ | 75.09 | $ | 78.32 | $ | 75.72 | $ | 77.62 | |||||||||
| NYMEX average monthly settled price ($/MMBtu) | $ | 2.79 | $ | 2.16 | $ | 2.88 | $ | 2.27 | $ | 2.74 | |||||||||
| Realized Prices as Percentage of Index Prices | |||||||||||||||||||
| Oil with derivative settlements as a percentage of Brent | 99 | % | 96 | % | 86 | % | 95 | % | 80 | % | |||||||||
| Oil without derivative settlements as a percentage of Brent | 98 | % | 98 | % | 99 | % | 96 | % | 98 | % | |||||||||
| Oil with derivative settlements as a percentage of WTI | 104 | % | 100 | % | 91 | % | 100 | % | 85 | % | |||||||||
| Oil without derivative settlements as a percentage of WTI | 104 | % | 103 | % | 105 | % | 102 | % | 104 | % | |||||||||
| NGLs as a percentage of Brent | 71 | % | 58 | % | 59 | % | 61 | % | 60 | % | |||||||||
| NGLs as a percentage of WTI | 75 | % | 61 | % | 63 | % | 65 | % | 63 | % | |||||||||
| Natural gas with derivative settlements as a percentage of NYMEX contract month average | 131 | % | 124 | % | 162 | % | 132 | % | 314 | % | |||||||||
| Natural gas without derivative settlements as a percentage of NYMEX contract month average | 131 | % | 124 | % | 162 | % | 132 | % | 314 | % | |||||||||
| Attachment 6 | |||||||||
| FOURTH QUARTER 2024 DRILLING ACTIVITY | |||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | ||||
| Development Wells | |||||||||
| Primary | 4 | — | — | — | 4 | ||||
| Waterflood | — | — | — | — | — | ||||
| Steamflood | — | — | — | — | — | ||||
| Total (1) | 4 | — | — | — | 4 | ||||
| TOTAL YEAR 2024 DRILLING ACTIVITY | |||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | ||||
| Development Wells | |||||||||
| Primary | 10 | — | — | — | 10 | ||||
| Waterflood | — | — | — | — | — | ||||
| Steamflood | — | — | — | — | — | ||||
| Total (1) | 10 | — | — | — | 10 | ||||
| (1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | |||||||||
| Attachment 7 | |||||||||||||||||||||
| OIL HEDGES AS OF DECEMBER 31, 2024 | |||||||||||||||||||||
| Q1 2025 | Q2 2025 | Q3 2025 | Q4 2025 | 2026 | 2027 | 2028 | |||||||||||||||
| Sold Calls | |||||||||||||||||||||
| Barrels per day | 30,000 | 30,000 | 30,000 | 29,000 | 15,000 | — | — | ||||||||||||||
| Weighted-average Brent price per barrel | $ | 87.08 | $ | 87.08 | $ | 87.08 | $ | 87.13 | $ | 85.00 | $ | — | $ | — | |||||||
| Swaps | |||||||||||||||||||||
| Barrels per day | 52,837 | 46,506 | 44,126 | 42,626 | 30,449 | 13,882 | 1,697 | ||||||||||||||
| Weighted-average Brent price per barrel | $ | 72.48 | $ | 71.31 | $ | 70.62 | $ | 69.94 | $ | 67.95 | $ | 65.53 | $ | 65.00 | |||||||
| Purchased Puts | |||||||||||||||||||||
| Barrels per day | 30,000 | 30,000 | 30,000 | 29,000 | 15,000 | — | — | ||||||||||||||
| Weighted-average Brent price per barrel | $ | 61.67 | $ | 61.67 | $ | 61.67 | $ | 61.72 | $ | 60.00 | $ | — | $ | — | |||||||
| Attachment 7 | |||||||||||||||||||||
| NATURAL GAS HEDGES AS OF DECEMBER 31, 2024 | |||||||||||||||||||||
| Q1 2025 | Q2 2025 | Q3 2025 | Q4 2025 | 2026 | 2027 | 2028 | |||||||||||||||
| SoCal Border | |||||||||||||||||||||
| MMBtu per day | 10,000 | 29,074 | 25,750 | 22,408 | 660 | — | — | ||||||||||||||
| Weighted-average price per MMBtu | $ | 6.02 | $ | 3.44 | $ | 3.48 | $ | 3.53 | $ | 6.29 | $ | — | $ | — | |||||||
| Northwest Pipeline (NWPL) Rockies | |||||||||||||||||||||
| MMBtu per day | 50,999 | 51,750 | 51,750 | 51,750 | 44,618 | 12,616 | 1,576 | ||||||||||||||
| Weighted-average price per MMBtu | $ | 5.48 | $ | 2.95 | $ | 2.95 | $ | 4.22 | $ | 4.01 | $ | 4.34 | $ | 3.95 | |||||||
| PG&E Citygate | |||||||||||||||||||||
| MMBtu per day | 14,000 | — | — | — | — | — | — | ||||||||||||||
| Weighted-average price per MMBtu | $ | 6.10 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||
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