California Resources Corporation
11/05/2025 | Press release | Distributed by Public on 11/05/2025 15:32
Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)
Item 2Management's Discussion and Analysis of Financial Condition and Results of Operations
General
We are an independent energy and carbon management company committed to energy transition. We are committed to environmental stewardship while safely providing local, responsibly sourced energy. We are also focused on maximizing the value of our land, mineral ownership, and energy expertise for decarbonization by developing carbon capture and storage (CCS) and other emissions-reducing projects.
Except when the context otherwise requires or where otherwise indicated, all references to ''CRC,'' the ''Company,'' ''we,'' ''us'' and ''our'' refer to California Resources Corporation and its consolidated subsidiaries as of the date presented.
Pending Berry Merger
On September 14, 2025, we entered into a definitive agreement and plan of merger (the Berry Merger Agreement) to combine with Berry Corporation (Berry) in an all-stock transaction (Berry Merger). Berry is an independent upstream energy company that operates in two business segments: (i) oil and natural gas and (ii) well servicing and abandonment services. Berry's oil and gas assets are located in California and Utah. We expect the transaction will add high quality, oil-weighted, mostly conventional proved developed reserves and sustainable cash flows to our operations.
Pursuant to the Berry Merger Agreement, on the effective date of the merger, we will issue 0.0718 shares of our common stock for each outstanding share of Berry stock. Upon completion of the Berry Merger, we expect our existing stockholders to own approximately 94% of the combined company upon closing.
We expect Berry's outstanding long-term debt to be repaid and the underlying credit agreement to be terminated at closing. We expect to repay a significant portion of this indebtedness with proceeds from our 2034 Senior Notes, which closed in October 2025. Berry's Revolving Credit Facility is also expected to be terminated at closing. For more information on the 2034 Senior Notes, refer to Part I, Item 1 - Financial Statements, Note 16 Subsequent Events.
Closing of the Berry Merger is subject to certain conditions, including, among others, adoption of the Berry Merger Agreement by its stockholders, expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, prior authorization by the Federal Energy Regulatory Commission under Section 203 of the Federal Power Act and other customary closing conditions. The Berry Merger is expected to close in the first quarter of 2026.
Business Environment and Industry Outlook
Commodity Prices
Our operating results, and those of the oil and natural gas industry, are heavily influenced by commodity prices. Oil and natural gas prices and differentials can fluctuate significantly due to various market-related factors, making it challenging to predict realized prices reliably. We may respond to changing economic conditions by adjusting the amount and allocation of our capital program or by pursuing additional efficiencies and cost savings. Prolonged volatility in oil and natural gas prices may also affect the quantities of reserves that we can economically produce over the longer term. Refer to Results of Our Oil and Natural Gas Operations, Production, Prices and Realizations below for information on our realized prices.
During 2025, oil prices experienced volatility driven by global supply and demand factors, including a series of announcements by OPEC+ indicating its intention to return offline production to the market more quickly than previously anticipated, and by concerns over global trade following multiple tariff announcements.
The following table presents the average daily benchmark prices for oil and natural gas during the periods presented:
| Three months ended | Nine months ended | ||||||||||||||||||||||
| September 30, | June 30, | September 30, | September 30, | ||||||||||||||||||||
| 2025 | 2025 | 2025 | 2024 | ||||||||||||||||||||
| Brent oil ($/Bbl) | $ | 68.13 | $ | 66.76 | $ | 69.94 | $ | 81.79 | |||||||||||||||
| WTI oil ($/Bbl) | $ | 64.93 | $ | 63.74 | $ | 66.70 | $ | 77.54 | |||||||||||||||
|
NYMEX Henry Hub ($/MMBtu)
|
$ | 3.07 | $ | 3.44 | $ | 3.39 | $ | 2.10 | |||||||||||||||
Supply Chain and Inflation
We continued to experience relatively flat pricing from our suppliers during the first nine months of 2025 compared to the prior year. U.S. tariff policy regarding both country of origin and material type remains highly uncertain and subject to future changes. The United States recently expanded tariff rates on imported goods including a 50% tariff on the steel and aluminum value of imported products. If sustained, these expanded tariff rates could increase our cost of oilfield goods and extend delivery lead times over the longer term. We have taken measures to limit the effects of potential price increases caused by the recent expansion of U.S. tariffs by entering into fixed price contracts with terms of one to three years for a significant majority of our materials and services based on our current expected development plans. We also pre-purchased inventory prior to the implementation of the tariffs and continue to purchase from vendors who source domestic content to limit the impact of foreign tariffs on our business. Overall, we expect minimal impact from tariffs on our supply chain in 2025. However, if the current tariff regime persists or expands, our inventory, capital and operating costs could increase over the long-term.
Marketing Arrangements
In October 2025, Phillips 66 closed its Wilmington refinery in Los Angeles, California. In April 2025, Valero notified the California Energy Commission of its intent to idle, restructure, or cease refining operations at its Benicia refinery in the San Francisco Bay Area by the end of April 2026. Although Valero has stated that it is in ongoing discussion with the California government, it recently confirmed plans to cease refining operations at Benicia and presently does not expect any changes to the previously announced timeline. We have historically sold a portion of our crude oil to these refineries.
Following the closure of the Phillips 66 refinery, and assuming Valero's Benicia refinery ceases operations, six major petroleum refineries would remain in California, each with a refining capacity exceeding 75,000 barrels per day. Five of these refineries currently purchase California crude oil. If Valero's Benicia refinery ceases operations, California would have approximately 1.1 million barrels per day of refining capacity available to process California crude oil, which is approximately four times the volume of crude oil produced in the state in 2024.
Given this available refining capacity and the flexibility we have in marketing our crude oil production, we do not currently expect the cessation of operations at these refineries, should the Valero Benicia refinery cease operations, to have a material impact on our ability to market our crude oil. While these announcements have not affected our price realizations to date, a reduction in the number of refineries operating in California has the potential to impact our future price realizations.
Regulatory Updates
Recent Legislation
Senate Bill 237 (Oil and Gas Permitting)
Senate Bill 237 (SB 237) was enacted in September 2025 and implements a number of changes to help facilitate new and continued oil and gas production in California (particularly in Kern County). Among other provisions, SB 237 deems a specified Kern County environmental impact report sufficient for full compliance with the requirements of the California Environmental Quality Act (CEQA) for purposes of a certain County of Kern zoning ordinance related to oil and gas activities and requires no further environmental review. These provisions of SB 237 will become effective as of January 1, 2026. We expect Kern County and the California Geologic Energy Management Division to resume issuing new well permits in Kern County in 2026 up to the maximum allowable amount of 2,000 new drill wells per year for up to ten years.
We believe that this legislation provides greater regulatory certainty for oil and gas operations in Kern County, which accounts for a substantial portion of California's crude oil and natural gas production. The adoption of SB 237 is particularly important to our business as we are the largest producer of oil and gas in Kern County and the majority of our production and reserves are located there. By facilitating the timely resumption of permitting activity, we expect that this legislation will support operational continuity and investment planning by California's oil and gas industry. In addition, we believe that the increased clarity around permitting standards will help to enhance long-term development opportunities in Kern County, benefiting both the broader industry and CRC's asset base in the region.
Assembly Bill 1207 (Cap-and-Invest Extension)
Assembly Bill 1207 (AB 1207) was enacted in September 2025. AB 1207 primarily extends California's greenhouse-gas Cap-and-Invest program through 2045, providing long-term policy certainty for covered entities under the Program. AB 1207 establishes emission reduction initiatives and enhances program transparency through expanded reporting requirements for the California Air Resources Board. The legislation also establishes a Climate Mitigation Fund to support consumer rebates and investments to reduce household energy costs.
Senate Bill 614 (Carbon Dioxide Pipeline Regulation)
Senate Bill 614 (SB 614), enacted in October 2025, revises the definition of "pipeline" for purposes of the Elder California Pipeline Safety Act of 1981 to include intrastate pipelines used for the transportation of carbon dioxide (CO₂). The law requires the Office of the State Fire Marshal to, by July 1, 2026, adopt implementing regulations regarding the safe transportation of CO₂ in pipelines, after which the current moratorium on CO₂ pipeline operations may be lifted. The legislation mandates stringent design, routing, and disclosure standards consistent with or exceeding federal requirements under the Pipeline and Hazardous Materials Safety Administration. Upon implementation, SB 614 is expected to enable the development of carbon-capture and storage infrastructure in California while imposing additional permitting, safety, and compliance obligations on operators of CO₂ transportation systems.
Well Permitting
During the three months ended September 30, 2025, we received well permits for 140 workovers and 89 sidetracks. During the nine months ended September 30, 2025, we have received total well permits for 279 workovers, 194 sidetracks and 5 deepenings.
We have not received any permits for new oil and gas wells in 2025. We believe that the enactment of SB 237 will ultimately result in CalGEM issuing new well permits beginning in 2026, and expect the rate of workover and sidetrack permit approvals to also increase throughout 2026.
We currently hold sufficient permits to exit the year with a four drilling rig capital program. Our ability to maintain a four drilling rig program throughout 2026 will require us to obtain new permits which we expect to become available in 2026 following the enactment of SB 237. See Liquidity and Capital Resources, Capital Program for more information.
For further information regarding well permitting, see Part I, Items 1 & 2 - Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities, Well Permittingin our 2024 Annual Report.
Kern County EIR Litigation
The Trial Court may act in the Kern County litigation matter later this year, although timing is uncertain. The enactment of SB 237 does not result in an immediate dismissal of the pending litigation, although it will provide support for dismissal of this litigation if it is still pending when the law becomes effective in January 2026. Developments in this litigation or in the permitting process more broadly that are adverse to Kern County could further adversely affect our business, results of operations and financial condition.
Statements of Operations Analysis
Our consolidated results of operations include the results of Aera beginning on July 1, 2024, the closing date of the Aera Merger. For more information on the Aera Merger, see Part I, Item 1 - Financial Statements, Note 2 Business Combinations. The Aera Merger affected the comparability of our financial results for the nine months ended September 30, 2025 to the prior comparative period.
Consolidated Results of Operations
Three months ended September 30, 2025 compared to June 30, 2025
The following table presents our consolidated operating revenues for the periods indicated:
| Three months ended | |||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||
| (in millions) | |||||||||||
|
Oil, natural gas and natural gas liquids sales
|
$ | 715 | $ | 702 | |||||||
|
Net (loss) gain from commodity derivatives
|
(23) | 157 | |||||||||
|
Revenue from marketing of purchased commodities
|
58 | 56 | |||||||||
|
Electricity revenue
|
101 | 58 | |||||||||
|
Other revenue
|
4 | 5 | |||||||||
| Total operating revenues | $ | 855 | $ | 978 | |||||||
Oil, natural gas and natural gas liquids sales - Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $715 million for the three months ended September 30, 2025, which is an increase of $14 million compared to $702 million for the three months ended June 30, 2025.
The following table shows changes in oil, natural gas and natural gas liquids sales for the three months ended September 30, 2025 compared to the three months ended June 30, 2025:
| Oil | NGLs | Natural Gas |
Total Operations
|
||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Three months ended June 30, 2025 | $ | 644 | $ | 39 | $ | 19 | $ | 702 | |||||||||||||||
|
Changes in realized prices
|
12 | (1) | 7 | 18 | |||||||||||||||||||
|
Changes in production and other
|
(3) | (2) | 3 | (2) | |||||||||||||||||||
|
Changes in intersegment revenues
|
- | - | (3) | (3) | |||||||||||||||||||
| Three months ended September 30, 2025 | $ | 653 | $ | 36 | $ | 26 | $ | 715 | |||||||||||||||
Note: See Production for volumes by commodity type and Prices and Realizationsfor index and realized prices for comparative periods.
Net (loss) gain from commodity derivatives - We report gains and losses on our derivative contracts related to sales of our oil and marketing activities in operating revenues. Net loss from commodity derivatives was $23 million for the three months ended September 30, 2025 compared to a net gain of $157 million for the three months ended June 30, 2025. The change primarily resulted from the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:
| Three months ended | |||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||
| (in millions) | |||||||||||
|
Non-cash commodity derivative (loss) gain
|
$ | (32) | $ | 140 | |||||||
|
Net proceeds and premium amortization
|
9 | 17 | |||||||||
|
Net (loss) gain from commodity derivatives
|
$ | (23) | $ | 157 | |||||||
Electricity revenue - Electricity revenue increased by$43 millionto $101 millionfor the three months ended September 30, 2025 compared to $58 million for the three months ended June 30, 2025. This increase was primarily a result of higher resource adequacy revenues during the three months ended September 30, 2025 compared to the three months ended June 30, 2025.
The following table presents our consolidated operating and non-operating expenses and income for the three months ended September 30, 2025 and June 30, 2025.
| Three months ended | |||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||
| (in millions) | |||||||||||
| Operating expenses | |||||||||||
|
Operating costs
|
$ | 316 | $ | 295 | |||||||
| General and administrative expenses | 87 | 79 | |||||||||
| Depreciation, depletion and amortization | 123 | 128 | |||||||||
| Asset impairment | 2 | - | |||||||||
| Taxes other than on income | 70 | 47 | |||||||||
|
Costs related to marketing of purchased commodities
|
44 | 41 | |||||||||
| Electricity generation expenses | 11 | 5 | |||||||||
|
Transportation costs
|
19 | 20 | |||||||||
| Accretion expense | 28 | 28 | |||||||||
| Net loss on natural gas purchase derivatives | 27 | 3 | |||||||||
| Other operating expenses, net | 29 | 65 | |||||||||
| Total operating expenses | 756 | 711 | |||||||||
|
Loss on asset divestitures
|
(1) | - | |||||||||
|
Operating income
|
98 | 267 | |||||||||
| Non-operating (expenses) income | |||||||||||
|
Interest and debt expense, net
|
(25) | (25) | |||||||||
|
Loss from investment in unconsolidated subsidiaries
|
(2) | - | |||||||||
|
Other non-operating income, net
|
4 | - | |||||||||
|
Income before income taxes
|
75 | 242 | |||||||||
|
Income tax provision
|
(11) | (70) | |||||||||
|
Net income
|
$ | 64 | $ | 172 | |||||||
Operating costs - The following table presents our operating costs for the three months ended September 30, 2025 and June 30, 2025:
| Three months ended | |||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||
| (in millions) | |||||||||||
| Energy operating costs | $ | 92 | $ | 78 | |||||||
| Gas processing costs | 6 | 5 | |||||||||
| Non-energy operating costs | 218 | 212 | |||||||||
|
Operating costs
|
$ | 316 | $ | 295 | |||||||
Energy operating costs consist of purchased natural gas used to generate electricity for our operations and steam for our steamfloods, purchased electricity and internal costs to produce electricity used in our operations. These internal costs include an allocation of the direct costs to produce electricity at our Elk Hills power plant based on electricity consumption by our Elk Hills and nearby fields. We do not allocate the costs to produce steam at our Elk Hills power plant which is then used in oil and natural gas operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.
Energy operating costs- Energy operating costs for the three months ended September 30, 2025 were $92 million, which was an increase of $14 million from $78 million for the three months ended June 30, 2025. This increase was primarily due to higher prices for electricity and natural gas used in our steamflood operations.
Taxes other than on income- Taxes other than on income for the three months ended September 30, 2025 were $70 million, which was an increase of $23 million from $47 million for the three months ended June 30, 2025. The three months ended June 30, 2025, included a downward adjustment to our estimated annual production tax rate. Greenhouse gas expense increased for the three months ended September 30, 2025 due to running the Elk Hills power plant at a higher operational capacity and market prices for purchased allowances were higher than prevailing market prices during the three months ended June 30, 2025.
Net loss on natural gas purchase derivatives - Net loss from derivatives related to our purchase of natural gas was $27 million for the three months ended September 30, 2025 compared to a net loss of $3 million for the three months ended June 30, 2025. The change primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held, as well as the relationship between contract prices and the associated forward curves at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:
| Three months ended | |||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||
| (in millions) | |||||||||||
|
Non-cash loss (gain) on natural gas purchase derivatives
|
$ | 24 | $ | (4) | |||||||
|
Settlements
|
3 | 7 | |||||||||
|
Net loss on natural gas purchase derivatives
|
$ | 27 | $ | 3 | |||||||
Other operating expenses, net- Other operating expenses, net decreased $36 million to$29 million for the three months ended September 30, 2025 compared to $65 million for the three months ended June 30, 2025. For the three months ended September 30, 2025 and June 30, 2025, other operating expenses, net includes the following:
| Three months ended | |||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||
| (in millions) | |||||||||||
|
Carbon management expenses
|
$ | 10 | $ | 14 | |||||||
|
Transaction and integration costs
|
6 | 3 | |||||||||
|
Severance
|
- | 6 | |||||||||
|
Signal Hill decommissioning expense
|
5 | 2 | |||||||||
|
Litigation and settlement related expenses(a)
|
1 | 25 | |||||||||
|
All other
|
7 | 15 | |||||||||
|
Total operating expenses, net
|
$ | 29 | $ | 65 | |||||||
(a)See Part I, Item 1 - Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for more information on a $25 million payment we made to CalGEM during the three months ended June 30, 2025.
Income taxes - The income tax provision for the three months ended September 30, 2025 was $11 million (representing an effective tax rate of 15%), compared to a provision of $70 million (representing an effective tax rate of 29%) for the three months ended June 30, 2025. The effective tax rate for the three months ended September 30, 2025, reflects the benefit related to guidance published for the marginal well tax credit. See Part I, Item 1 - Financial Statements, Note 7 Income Taxes.
Nine months ended September 30, 2025 compared to September 30, 2024
The following table presents our consolidated operating revenues for the periods indicated:
| Nine months ended | |||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||
| (in millions) | |||||||||||
|
Oil, natural gas and natural gas liquids sales
|
$ | 2,231 | $ | 1,711 | |||||||
| Net gain from commodity derivatives | 140 | 290 | |||||||||
|
Revenue from marketing of purchased commodities
|
178 | 176 | |||||||||
|
Electricity revenue
|
181 | 120 | |||||||||
|
Other revenue
|
15 | 24 | |||||||||
| Total operating revenues | $ | 2,745 | $ | 2,321 | |||||||
Oil, natural gas and natural gas liquids sales - Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $2,231 million for the nine months ended September 30, 2025, which is an increase of $520 million compared to $1,711 million for the nine months ended September 30, 2024.
The following table shows changes in oil, natural gas and natural gas liquids sales for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024.
| Oil | NGLs | Natural Gas |
Total Operations
|
||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Nine months ended September 30, 2024 | $ | 1,505 | $ | 138 | $ | 68 | $ | 1,711 | |||||||||||||||
|
Changes in realized prices
|
(206) | (5) | 22 | (189) | |||||||||||||||||||
|
Changes in production and other (a)
|
734 | (8) | 1 | 727 | |||||||||||||||||||
|
Changes in intersegment revenues
|
- | - | (18) | (18) | |||||||||||||||||||
| Nine months ended September 30, 2025 | $ | 2,033 | $ | 125 | $ | 73 | $ | 2,231 | |||||||||||||||
Note: See Production for volumes by commodity type and Prices and Realizationsfor index and realized prices for comparative periods.
(a)The increase in production primarily relates to the addition of the Aera fields on July 1, 2024. See Part I, Item 1 - Financial Statements, Note 2 Business Combinations for additional information.
Net gain from commodity derivatives- We report gains and losses on our derivative contracts related to sales of our produced oil and marketing activities in operating revenue. Net gain from commodity derivatives was $140 million for the nine months ended September 30, 2025 compared to a net gain of $290 million for the nine months ended September 30, 2024. The change primarily resulted from payments to settle commodity derivative contracts and the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:
| Nine months ended | |||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||
| (in millions) | |||||||||||
|
Non-cash commodity derivative gain
|
$ | 130 | $ | 325 | |||||||
|
Net proceeds (settlements) and premium amortization
|
10 | (35) | |||||||||
|
Net gain from commodity derivatives
|
$ | 140 | $ | 290 | |||||||
Electricity revenue - Electricity revenue increased by $61 million to $181 million for the nine months ended September 30, 2025 compared to $120 million for the nine months ended September 30, 2024. This increase was primarily a result of higher pricing from resource adequacy contracts. Additionally, we experienced lower revenues during the nine months ended September 30, 2024 as a result of downtime at our Elk Hills power plant.
The following table presents our consolidated operating and non-operating expenses and income for the nine months ended September 30, 2025 and September 30, 2024.
| Nine months ended | |||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||
| (in millions) | |||||||||||
| Operating expenses | |||||||||||
|
Operating costs
|
$ | 927 | $ | 643 | |||||||
| General and administrative expenses | 238 | 226 | |||||||||
| Depreciation, depletion and amortization | 382 | 246 | |||||||||
| Asset impairment | 2 | 13 | |||||||||
| Taxes other than on income | 187 | 162 | |||||||||
|
Costs related to marketing of purchased commodities
|
135 | 140 | |||||||||
| Electricity generation expenses | 26 | 31 | |||||||||
|
Transportation costs
|
59 | 60 | |||||||||
| Accretion expense | 85 | 56 | |||||||||
| Net loss on natural gas purchase derivatives | 24 | 11 | |||||||||
|
Measurement period adjustments, net
|
1 | - | |||||||||
| Other operating expenses, net | 127 | 188 | |||||||||
| Total operating expenses | 2,193 | 1,776 | |||||||||
|
(Loss) gain on asset divestitures
|
(1) | 7 | |||||||||
|
Operating income
|
551 | 552 | |||||||||
| Non-operating (expenses) income | |||||||||||
|
Interest and debt expense, net
|
(77) | (59) | |||||||||
|
Loss on early extinguishment of debt
|
(1) | (5) | |||||||||
|
Loss from investment in unconsolidated subsidiaries
|
(3) | (9) | |||||||||
|
Other non-operating income (expenses), net
|
9 | (4) | |||||||||
|
Income before income taxes
|
479 | 475 | |||||||||
|
Income tax provision
|
(128) | (132) | |||||||||
|
Net income
|
$ | 351 | $ | 343 | |||||||
Operating costs - The following table presents our operating costs for the nine months ended September 30, 2025 and September 30, 2024.
| Nine months ended | |||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||
| (in millions) | |||||||||||
| Energy operating costs | $ | 273 | $ | 186 | |||||||
| Gas processing costs | 15 | 12 | |||||||||
| Non-energy operating costs | 639 | 445 | |||||||||
|
Operating costs
|
$ | 927 | $ | 643 | |||||||
Energy operating costs- Energy operating costs for the nine months ended September 30, 2025 were $273 million, which was an increase of $87 million from $186 millionfor the nine months ended September 30, 2024. The increase is primarily related to the addition of the Aera fields for the full nine months of 2025 compared to the same prior year period. Excluding the Aera fields, our energy operating costs for the nine months ended September 30, 2025 decreased primarily due to the additional supply of electricity generated at our Elk Hills power plant which is used at our Elk Hills field. During the nine months ended September 30, 2024, our Elk Hills power plant experienced unplanned downtime and scheduled maintenance.
Non-energy operating costs - Non-energy operating costs for the nine months ended September 30, 2025 were $639 million, which was an increase of $194 millionfrom $445 millionfor the nine months ended September 30, 2024. The increase is primarily related to the operation of the Aera fields for the full nine months of 2025 compared to a three-month period in the same prior year period. We also had higher surface maintenance activity during the nine months ended September 30, 2025 compared to the same prior year period.
General and administrative expenses- General and administrative (G&A) expenses were $238 million for the nine months ended September 30, 2025 compared to $226 million for the nine months ended September 30, 2024, which was an increase of $12 million. The increase was primarily due to additional compensation-related expense and other corporate expenses resulting from the Aera Merger.
Depreciation, depletion and amortization- Depreciation, depletion and amortization (DD&A) for the nine months ended September 30, 2025 was $382 million compared to $246 million during the nine months ended September 30, 2024. The increase of $136 million was primarily the result of the addition of the Aera assets included in the nine months ended September 30, 2025. See Part I, Item 1 - Financial Statements, Note 2 Business Combinations for information on the Aera assets.
Asset impairments - During the nine months ended September 30, 2024, we recognized a $13 million impairment for excess and obsolete materials and supplies related to our oilfield operations. We recognized a $2 million asset impairment during the nine months ended September 30, 2025 related to a fair value adjustment for properties held for sale. See Part I, Item 1 - Financial Statements, Note 8 Divestitures and Acquisitions for additional information on the impairment.
Taxes other than on income- Taxes other than on income for the nine months ended September 30, 2025 were $187 million, which is an increase of $25 million from $162 million for the nine months ended September 30, 2024. This increasewas a result of higher greenhouse gas expense, production taxes and ad valorem taxes related to the Aera assets following the completion of the Aera Merger.
Accretion expense - Accretion expense for the nine months ended September 30, 2025 was $85 million compared to $56 million for the nine months ended September 30, 2024. The increase was primarily due to the addition of the Aera asset retirement liability assumed as of July 1, 2024 in connection with the Aera Merger.
Net loss on natural gas purchased derivatives - Net loss from derivatives related to our purchase of natural gas was $24 million for the nine months ended September 30, 2025 compared to a net loss of $11 million for the nine months ended September 30, 2024. The change primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held, as well as the relationship between contract prices and the associated forward curves at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:
| Nine months ended | |||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||
| (in millions) | |||||||||||
|
Non-cash loss (gain) on natural gas purchase derivatives
|
$ | 2 | $ | (7) | |||||||
|
Settlements
|
22 | 18 | |||||||||
| Net loss on natural gas purchase derivatives | $ | 24 | $ | 11 | |||||||
Other operating expenses, net- Other operating expenses, net decreased $61 million to $127 million for the nine months ended September 30, 2025 compared to $188 million for the nine months ended September 30, 2024.
For the nine months ended September 30, 2025 and September 30, 2024, other operating expenses, net includes the following:
| Nine months ended | |||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||
| (in millions) | |||||||||||
|
Carbon management business expense
|
$ | 42 | $ | 36 | |||||||
|
Transaction and integration costs
|
10 | 56 | |||||||||
|
Energy costs due to downtime at Elk Hills power plant
|
- | 44 | |||||||||
|
Severance
|
8 | 28 | |||||||||
|
Litigation and settlement related expenses(a)
|
26 | 7 | |||||||||
|
Offshore platforms maintenance and abandonment
|
7 | 2 | |||||||||
|
Information technology infrastructure
|
11 | - | |||||||||
|
All other
|
23 | 15 | |||||||||
|
Total operating expenses, net
|
$ | 127 | $ | 188 | |||||||
(a)See Part I, Item 1 - Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for more information on a $25 million payment we made to CalGEM during the nine months ended September 30, 2025.
Interest and debt expense, net - Interest and debt expense, net was $77 million for the nine months ended September 30, 2025 compared to $59 million for the nine months ended September 30, 2024. The increase was predominantly due to higher interest expense resulting from the issuance of our 2029 Senior Notes. In June 2024, we issued $600 million in aggregate principal amount of 2029 Senior Notes and in August 2024, we completed a follow-on offering of $300 million in aggregate principal amount of 2029 Senior Notes.
Income taxes - The income tax provision for the nine months ended September 30, 2025 was $128 million (representing an effective tax rate of 27%), compared to a provision of $132 million (representing an effective tax rate of 28%) for the nine months ended September 30, 2024. See Part I, Item 1 - Financial Statements, Note 7 Income Taxesfor additional information on our income taxes.
For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the 2026 Senior Notes Indenture and 2029 Senior Notes Indenture, see Part I, Item 1 - Financial Statements, Note 15 Condensed Consolidated Financial Information.
Results of Our Oil and Natural Gas Operations
The following table includes financial results and key operating data for our oil and natural gas segment for the three months ended September 30, 2025 and June 30, 2025 and the nine months ended September 30, 2025 and 2024.
| Three months ended | Nine months ended | ||||||||||||||||||||||
| September 30, | June 30, | September 30, | September 30, | ||||||||||||||||||||
| 2025 | 2025 | 2025 | 2024 | ||||||||||||||||||||
|
(in millions, except as otherwise stated)
|
|||||||||||||||||||||||
|
Production and oil and gas segment financial data
|
|||||||||||||||||||||||
|
Net production sold (MBoe/d)
|
137 | 137 | 138 | 99 | |||||||||||||||||||
|
Total operating revenues
|
$ | 728 | $ | 714 | $ | 2,272 | $ | 1,734 | |||||||||||||||
|
Segment profit
|
$ | 182 | $ | 194 | $ | 642 | $ | 547 | |||||||||||||||
|
Items affecting comparability:
|
|||||||||||||||||||||||
|
Net (loss) gain on asset divestitures(a)
|
$ | (1) | $ | - | $ | (1) | $ | 6 | |||||||||||||||
|
Key operating expenses per Boe
|
|||||||||||||||||||||||
|
Operating costs
|
$ | 25.54 | $ | 24.19 | $ | 25.11 | $ | 24.11 | |||||||||||||||
|
Operating costs, after hedges on purchased natural gas
|
$ | 25.75 | $ | 24.75 | $ | 25.68 | $ | 24.76 | |||||||||||||||
|
General and administrative expenses(b)
|
$ | 0.72 | $ | 0.72 | $ | 0.80 | $ | 2.65 | |||||||||||||||
|
Depreciation, depletion and amortization(c)
|
$ | 9.39 | $ | 9.69 | $ | 9.68 | $ | 8.55 | |||||||||||||||
|
Taxes other than on income
|
$ | 4.54 | $ | 3.28 | $ | 4.16 | $ | 5.05 | |||||||||||||||
(a)Net loss on asset divestitures for the three and nine months ended September 30, 2025 related to the sale of oil and gas assets located in Ventura. Net gain on asset divestitures for the nine months ended September 30, 2024 related to the sale of our Fort Apache parcel in Huntington Beach.
(b)Includes general and administrative expenses allocated to our oil and natural gas segment.
(c)Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant.
Production, Prices, and Realizations
Net Production Sold
The following table presents our net production sold per day in each of the California basins in which we operate for the periods presented. The amounts in the production table below include volumes produced from operated and non-operated fields for each of the periods presented.
| Three months ended | Nine months ended | ||||||||||||||||||||||
| September 30, | June 30, | September 30, | September 30, | ||||||||||||||||||||
| 2025 | 2025 | 2025 | 2024 | ||||||||||||||||||||
| Oil (MBbl/d) | |||||||||||||||||||||||
| San Joaquin Basin | 81 | 83 | 83 | 50 | |||||||||||||||||||
| Los Angeles Basin | 17 | 17 | 17 | 17 | |||||||||||||||||||
|
Other Basins
|
9 | 9 | 9 | 2 | |||||||||||||||||||
| Total | 107 | 109 | 109 | 69 | |||||||||||||||||||
| NGLs (MBbl/d) | |||||||||||||||||||||||
| San Joaquin Basin | 10 | 10 | 10 | 11 | |||||||||||||||||||
| Total | 10 | 10 | 10 | 11 | |||||||||||||||||||
| Natural gas (MMcf/d) | |||||||||||||||||||||||
| San Joaquin Basin | 103 | 96 | 100 | 99 | |||||||||||||||||||
| Los Angeles Basin | 1 | 1 | 1 | 1 | |||||||||||||||||||
|
Sacramento Basin
|
11 | 12 | 12 | 14 | |||||||||||||||||||
|
Other Basins
|
3 | 2 | 2 | - | |||||||||||||||||||
| Total | 118 | 111 | 115 | 114 | |||||||||||||||||||
|
Total Net Production Sold (MBoe/d)
|
137 | 137 | 138 | 99 | |||||||||||||||||||
Total average net production sold remained flat at 137MBoe/d for the three months ended September 30, 2025 compared to the three months ended June 30, 2025. Our production-sharing contracts (PSCs), which are described below, positively impacted our net oil production by 1 MBoe/d in the three months ended September 30, 2025 compared to the three months ended June 30, 2025. This positive production impact was offset by natural decline.
Total average net production sold increased to 138MBoe/d for the nine months ended September 30, 2025 compared to 99MBoe/d for the nine months ended September 30, 2024. The increase was primarily a result of the Aera Merger. Our PSCs, which are described below, positively impacted our net oil production by approximately 2 MBoe/d in the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024.
Production-Sharing Contracts
Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts that are in effect through the economic life of the assets. The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs.
For further information on our production-sharing contracts, see Part I, Item 1 & 2 Business and Properties, Oil and Natural Gas Operations, Production, Price and Cost Historyin our 2024 Annual Report.
Prices and Realizations
The following tables set forth the average realized prices and price realizations on the commodities we sell as a percentage of average Brent, WTI and NYMEX Henry Hub indexes for our oil and natural gas operations for the periods presented:
| Three months ended | |||||||||||||||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||||||||||||||
| Price | Realization | Price | Realization | ||||||||||||||||||||
| Oil ($ per Bbl) | |||||||||||||||||||||||
| Brent | $ | 68.13 | $ | 66.76 | |||||||||||||||||||
| Realized price without derivative settlements | $ | 66.32 | 97% | $ | 65.07 | 97% | |||||||||||||||||
| Derivative settlements | 0.72 | 1.66 | |||||||||||||||||||||
| Realized price with derivative settlements | $ | 67.04 | 98% | $ | 66.73 | 100% | |||||||||||||||||
| WTI | $ | 64.93 | $ | 63.74 | |||||||||||||||||||
| Realized price without derivative settlements | $ | 66.32 | 102% | $ | 65.07 | 102% | |||||||||||||||||
| Realized price with derivative settlements | $ | 67.04 | 103% | $ | 66.73 | 105% | |||||||||||||||||
|
Natural Gas Liquids ($ per Bbl)
|
|||||||||||||||||||||||
| Realized price (% of Brent) | $ | 41.04 | 60% | $ | 42.41 | 64% | |||||||||||||||||
| Realized price (% of WTI) | $ | 41.04 | 63% | $ | 42.41 | 67% | |||||||||||||||||
| Natural gas | |||||||||||||||||||||||
|
NYMEX Henry Hub ($/MMBtu)
|
$ | 3.07 | $ | 3.44 | |||||||||||||||||||
| Realized price ($/Mcf) | $ | 3.47 | 113% | $ | 2.79 | 81% | |||||||||||||||||
| Nine months ended | |||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||||||||||||||
| Price | Realization | Price | Realization | ||||||||||||||||||||
| Oil ($ per Bbl) | |||||||||||||||||||||||
| Brent | $ | 69.94 | 81.79 | ||||||||||||||||||||
| Realized price without derivative settlements | $ | 68.34 | 98% | $ | 79.15 | 97% | |||||||||||||||||
| Derivative settlements | 0.27 | (2.05) | |||||||||||||||||||||
| Realized price with derivative settlements | $ | 68.61 | 98% | $ | 77.10 | 94% | |||||||||||||||||
| WTI | $ | 66.70 | $ | 77.54 | |||||||||||||||||||
| Realized price without derivative settlements | $ | 68.34 | 102% | $ | 79.15 | 102% | |||||||||||||||||
| Realized price with derivative settlements | $ | 68.61 | 103% | $ | 77.10 | 99% | |||||||||||||||||
|
Natural Gas Liquids ($ per Bbl)
|
|||||||||||||||||||||||
| Realized price (% of Brent) | $ | 46.10 | 66% | $ | 47.77 | 58% | |||||||||||||||||
| Realized price (% of WTI) | $ | 46.10 | 69% | $ | 47.77 | 62% | |||||||||||||||||
| Natural gas | |||||||||||||||||||||||
|
NYMEX Henry Hub ($/MMBtu)
|
$ | 3.39 | $ | 2.10 | |||||||||||||||||||
| Realized price ($/Mcf) | $ | 3.46 | 102% | $ | 2.76 | 131% | |||||||||||||||||
Oil- Brent price movements in 2025 have been dominated by OPEC+ signaling higher output, which put downward pressure on prices during the three months ended June 30, 2025. Brent prices rebounded during the three months ended September 30, 2025 as output was lower than expected and seasonal demand. Brent oil prices were lower for the nine months ended September 30, 2025 compared to the same period in 2024 as OPEC+ shifted their production cuts and quotas to increase supply. See Business Environment and Industry Outlookabove for more information on factors influencing Brent commodity prices for the periods presented.
NGLs- Prices for natural gas liquids during the three months ended September 30, 2025 decreased compared to the three months ended June 30, 2025, reflecting typical seasonal patterns. Prices for natural gas liquids during the nine months ended September 30, 2025 were lower than in the same prior year period, consistent with broader declines in oil commodity prices.
Natural Gas- Natural gas index prices decreased for the three months ended September 30, 2025 compared to the three months ended June 30, 2025 driven by substantial natural gas production relative to modest demand for electricity generation. Realized natural gas prices in California were higher in the three months ended September 30, 2025 compared to the three months ended June 30, 2025 reflecting pipeline system maintenance and constraints impacting natural gas deliveries into California. Natural gas prices increased for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 driven by higher demand in 2025 and the effects of elevated inventories in the prior year.
Results of Our Carbon Management Segment
Our carbon management segment, which we refer to as Carbon TerraVault, primarily pursues the development of CCS projects. We expect that our Carbon TerraVault CCS projects will inject CO2captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO2deep underground. We also expect to invest in projects that rely on CCS technology in connection with reducing our own emissions. In addition, we may participate in the development of projects that are the source of these CO2emissions. Our carbon management segment is in its early stages of development. We expect construction of our first carbon capture project at our cryogenic gas processing facility to be completed at or around year end. We expect first injection in 2026, subject to receipt of final regulatory approvals.
The following tables include results for our carbon management segment for the three months ended September 30, 2025 and June 30, 2025 and the nine months ended September 30, 2025 and September 30 2024.
| Three months ended | Nine months ended | ||||||||||||||||||||||
| September 30, | June 30, | September 30, | September 30, | ||||||||||||||||||||
| 2025 | 2025 | 2025 | 2024 | ||||||||||||||||||||
| (in millions) | (in millions) | ||||||||||||||||||||||
|
Segment loss
|
$ | (21) | $ | (20) | $ | (66) | $ | (63) | |||||||||||||||
| Three months ended | Nine months ended | ||||||||||||||||||||||
| September 30, | June 30, | September 30, | September 30, | ||||||||||||||||||||
| 2025 | 2025 | 2025 | 2024 | ||||||||||||||||||||
| (in millions) | (in millions) | ||||||||||||||||||||||
|
Carbon management expenses
|
$ | 10 | $ | 14 | $ | 42 | $ | 36 | |||||||||||||||
|
Segment general and administrative expenses
|
$ | 4 | $ | 3 | $ | 10 | $ | 10 | |||||||||||||||
|
Loss from investment in the Carbon TerraVault JV
|
$ | 2 | $ | 1 | $ | 4 | $ | 10 | |||||||||||||||
Carbon management expenses decreased for the three months ended September 30, 2025compared to the three months ended June 30, 2025 as a result of lower legal and compensation expenses.
Carbon management expenses increased for the nine months ended September 30, 2025compared to the ninemonths ended September 30, 2024 as a result of increased expenditure related to the evaluation of CCS projects and increased lease cost.
Liquidity and Capital Resources
Liquidity
Our primary sources of liquidity and capital resources are cash flows from operations, available cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the three and nine months ended September 30, 2025 were for repurchases of our common stock, payment of dividends, and capital investments.
The following table summarizes our liquidity:
| September 30, 2025 | |||||
| (in millions) | |||||
|
Available cash and cash equivalents(a)
|
$ | 180 | |||
| Revolving Credit Facility: | |||||
|
Borrowing capacity
|
$ | 1,150 | |||
| Outstanding letters of credit | (176) | ||||
| Availability | $ | 974 | |||
| Liquidity | $ | 1,154 | |||
(a)Excludes restricted cash of $16 million.
At current commodity prices and based upon our planned 2025 capital program described below, we expect to generate operating cash flow to return cash to shareholders through dividends and repurchases of our common stock. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or share repurchases to the extent permitted under our Revolving Credit Facility, our 8.25% senior notes due 2029 (2029 Senior Notes), and our 7.00% senior notes due 2034 (2034 Senior Notes) (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We continue to monitor the current macroeconomic environment and will adjust our planned uses of cash as necessary. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.
Revolving Credit Facility
See Part II, Item 8 - Financial Statements and Supplementary Data, Note 5 Debt in our 2024 Annual Report for information on the Revolving Credit Facility and related amendments. See Part I, Item 1 - Financial Statements, Note 16 Subsequent Events for information on a recent amendment to our Revolving Credit Facility.
2034 Senior Notes
See Part I, Item 1 - Financial Statements, Note 16 Subsequent Events for information on our 2034 Senior Notes.
2026 Senior Notes Redemption
See Part I, Item 1 - Financial Statements, Note 4 Debt andNote 16 Subsequent Events for information on the redemption of our 2026 Senior Notes.
Share Repurchase Program
See Part I, Item 1 - Financial Statements, Note 10 Stockholders' Equity and Part II, Item 2 - Other Information, Unregistered Sales of Equity Securities and Use of Proceeds for more information on our Share Repurchase Program.
Dividends
See Part I, Item 1 - Financial Statements, Note 10 Stockholders' Equity for more information on our dividends. See Part I, Item 1 - Financial Statements, Note 16 Subsequent Events for information on an increased dividend declared in November 2025.
Capital Program
Our capital investment for the nine months ended September 30, 2025was $202 million. We expect our full year 2025 capital program to range between $280 millionand $330 million. Of this amount, $250 million to $275 million is related to our oil and natural gas segment, $20 million to $40 million is for our carbon management segment and $10 million to $15 million is for corporate and other activities. The above amounts related to carbon management projects do not include amounts funded by Brookfield through the Carbon TerraVault JV, such as drilling injection and monitoring wells at our 26R reservoir.
With respect to oil and natural gas development, we ran an average of two rigs during the three months ended September 30, 2025 and expect to exit the year with four rigs. Refer to Regulatory Updatesabove for more information on permitting. Refer to Part I, Item 1 - Financial Statements, Note 9 Segment Information for information on capital investment by segment.
We plan to average four rigs during 2026, which activity is underpinned by the strength of hedges currently in place. We expect to operate four rigs using existing permits and new permits which we expect to become available in 2026 following the recent enactment of SB 237. We retain the flexibility to adjust our 2026 capital plan to reflect changes in commodity prices and other market factors. This program does not include the impact of the Berry Merger.
Derivatives
Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining oil prices negatively affect our operating cash flow, and the inverse applies during periods of rising oil prices. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. We will continue to evaluate our hedging strategy based on prevailing market prices and conditions.
Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the nine months ended September 30, 2025. See Part I, Item 1 - Financial Statements, Note 6 Derivativesfor further information on our derivatives and a summary of our open derivative contracts as of September 30, 2025 and Part II, Item 8 - Financial Statements and Supplementary Data, Note 5 Debt in our 2024 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.
Cash Flow Analysis
Cash flows from operating activities- For the nine months ended September 30, 2025, our operating cash flow increased by $226 million to $630 million from $404 million in the same period in 2024. This increase in operating cash flow was primarily driven by the Aera Merger on July 1, 2024.
Oil production during the nine months ended September 30, 2025 as compared to the same period in 2024 increased 40 MBbl/d from 69MBbl/d to 109 MBbl/d as a result of the Aera Merger. Higher revenue from this increase in production was partially offset by lower average realized oil prices (after derivative settlements). Average realized prices for oil decreased by $8.49 per barrel to $68.61in the nine months ended September30, 2025 from $77.10in the same prior year period. Further, as a result of the Aera Merger, we experienced higher operating costs, employee costs, well abandonment costs, production taxes and greenhouse gas taxes during the nine months ended September30, 2025 as compared to the same prior year period.
During the nine months ended September30, 2024, downtime at the Elk Hills power plant negatively impacted our production and we purchased electricity at higher prices.
Cash flows used in investing activities- The following table provides a comparative summary of net cash used in investing activities:
|
Nine months ended September 30, |
|||||||||||
| 2025 | 2024 | ||||||||||
| (in millions) | |||||||||||
| Capital investments | $ | (202) | $ | (167) | |||||||
| Changes in accrued capital investments | (10) | 8 | |||||||||
|
Proceeds from asset divestitures
|
2 | 12 | |||||||||
|
Purchase of a business, net of cash acquired
|
- | (853) | |||||||||
| Acquisitions | - | (6) | |||||||||
| Other, net | (7) | (4) | |||||||||
| Net cash used in investing activities | $ | (217) | $ | (1,010) | |||||||
Cash flows used in financing activities- The following table provides a comparative summary of net cash used in financing activities:
|
Nine months ended September 30, |
|||||||||||
| 2025 | 2024 | ||||||||||
| (in millions) | |||||||||||
|
Proceeds from Revolving Credit Facility
|
$ | 150 | $ | 30 | |||||||
| Repayments of Revolving Credit Facility | (150) | (30) | |||||||||
|
Proceeds from 2029 Senior Notes, net
|
- | 888 | |||||||||
|
Repurchases of common stock(a)
|
(352) | (135) | |||||||||
| Common stock dividends | (102) | (77) | |||||||||
|
Dividend equivalents on equity-settled awards
|
(1) | (4) | |||||||||
| Issuance of common stock | 2 | 2 | |||||||||
|
Bridge loan commitment costs
|
- | (5) | |||||||||
|
Debt redemption
|
(123) | (303) | |||||||||
|
Debt amendment costs
|
- | (10) | |||||||||
|
Debt issuance costs
|
(1) | - | |||||||||
|
Stock warrants exercised
|
- | 37 | |||||||||
| Shares cancelled for taxes | (12) | (42) | |||||||||
|
Net cash (used in) provided by financing activities
|
$ | (589) | $ | 351 | |||||||
(a)Note: The total value of shares purchased includes excise taxes, which are generally paid in the year following the share repurchase. Commissions paid on share repurchases were not significant in all periods presented.
For the nine months ended September 30, 2025, our cash flow used in financing activities was $589 million compared to cash flow provided by financing activities of $351 million in the same period in 2024. This decrease in cash flow from financing activities was primarily driven by the $888 million of proceeds from 2029 Senior Notes issued in the nine months ended September 30, 2024. Additionally, the decrease is caused by the $352 million cash outflow used to repurchase stock in the nine months ended September 30, 2025 compared to $135 million in the nine months ended September 30, 2024.
Divestitures and Assets Held for Sale
SeePart I, Item 1 - Financial Statements, Note 8 Divestitures and Assets Held for Salefor information on our divestitures and acquisitions during the three months ended September 30, 2025 and 2024.
Lawsuits, Claims, Commitments and Contingencies
See Part I, Item 1 - Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingenciesfor further information.
Critical Accounting Estimates and Significant Accounting and Disclosure Changes
There have been no changes to our critical accounting estimates, which are summarized in Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimatesof our 2024 Annual Report.
Forward-Looking Statements
This document contains statements that we believe 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 our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as "expect," "could," "may," "anticipate," "intend," "plan," "ability," "believe," "seek," "see," "will," "would," "estimate," "forecast," "target," "guidance," "outlook," "opportunity" or "strategy" or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.
Although we believe the expectations and forecasts reflected in our 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 our 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 our actual results to be materially different than those expressed in our forward-looking statements include:
•fluctuations in commodity prices, including supply and demand considerations for our 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 our 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 our products;
•the expected timing and resumption of the issuance of well permits following the enactment of SB 237;
•the efforts of activists to delay prevent oil and gas activities or the development of our carbon management segment through a variety of tactics, including litigation;
•the impact of inflation, tariffs and changes in domestic or global trade policies on future expenses and changes generally in the prices of goods and services;
•changes in business strategy and our capital plan;
•lower-than-expected production or higher-than-expected production decline rates;
•changes to our estimates of reserves and related future cash flows, including changes arising from our 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 we operate;
•our 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 our counterparties, including financial institutions, operating partners, CCS project participants and other parties;
•reorganization or restructuring of our operations;
•our ability to claim and utilize tax credits or other incentives in connection with our CCS projects;
•our ability to realize the benefits contemplated by our energy transition
strategies and initiatives, including CCS projects and other renewable energy efforts;
•our ability to successfully identify, develop and finance carbon capture and storage projects, power projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and our ability to convert our CDMAs to definitive agreements and enter into other offtake agreements;
•our ability to maximize the value of our carbon management segment and operate it on a stand alone basis;
•our ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;
•uncertainty around the accounting of emissions and our ability to successfully gather and verify emissions data and other environmental impacts;
•changes to our dividend policy and share repurchase program, and our ability to declare future dividends or repurchase shares under our debt agreements;
•limitations on our financial flexibility due to existing and future debt;
•insufficient cash flow to fund our capital plan and other planned investments and return capital to shareholders;
•changes in interest rates;
•our access to and the terms of credit in commercial banking and capital markets, including our ability to refinance our debt or obtain separate financing for our carbon management segment;
•changes in state, federal or international tax rates, including our ability to utilize our net operating loss carryforwards to reduce our income tax obligations;
•effects of hedging transactions;
•the effect of our 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 our 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;
•transaction costs;
•unknown liabilities
•the risk that any announcements relating to the Berry Merger could have adverse effects on the market price of our common stock;
•the ability to successfully integrate Berry;
•the ability to achieve projected synergies from the Berry Merger or it may take longer than expected to achieve synergies;
•risks related to financial community and rating agency perceptions of us and our business, operations, financial condition and the industry in which we operate;
•the occurrence of any event, change or other circumstances that could give rise to the termination of the Berry Merger;
•the risk that stockholders of Berry may not approve the Berry Merger;
•the risk that the any of the other closing conditions to the Berry Merger may not be satisfied in a timely manner, including the risk that all necessary regulatory approvals may not be obtained or may be obtained subject to conditions that are not anticipated;
•risks related to disruption of management time from ongoing business operations due to the Berry transaction;
•effects of the announcement, pendency or completion of the transaction on our ability to retain customers and retain and hire key personnel and maintain relationships with our suppliers and customers; and
•other factors discussed in Part I, Item 1A - Risk Factors of our 2024 Annual Report.
We caution you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and we undertake 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 we have not independently verified them and do not warrant the accuracy or completeness of such third-party information.
California Resources Corporation published this content on November 05, 2025, and is solely responsible for the information contained herein. Distributed via Edgar on November 05, 2025 at 21:34 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]