California Resources Corporation
03/02/2026 | Press release | Distributed by Public on 03/02/2026 15:36
Annual Report for Fiscal Year Ending December 31, 2025 (Form 10-K)
ITEM 7MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with other sections of this report, including but not limited to, Part I, Item 1 and 2 - Business and Propertiesand Part II, Item 8 - Financial Statements and Supplementary Data.
See Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operationsin our Annual Report on Form 10-K for the year ended December 31, 2024 (2024 Annual Report) for our analysis of the changes in our consolidated statements of operations and statements of cash flows for the year ended December 31, 2024 compared to December 31, 2023.
Basis of Presentation
All financial information presented consists of our consolidated results of operations, financial position and cash flows unless otherwise indicated. We have eliminated all intercompany transactions and accounts. We account for our share of oil and natural gas production activities, in which we have a direct working interest by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on our balance sheets and statements of operations and cash flows. In applying the equity method of accounting, our investments in our unconsolidated subsidiaries are recognized either at cost, as is the case with Carbon TerraVault JV HoldCo, LLC, or at fair value if acquired in a business combination, as is the case for Midway Sunset Cogeneration Company. These investments are thenadjusted for our proportionate share of income or loss in addition to contributions and distributions.
Supply Chain and Inflation
We continued to experience relatively flat pricing from our suppliers during the year ended December 31, 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. During 2025, the United States 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 2026. However, if the current tariff regime persists or expands, our inventory, capital and operating costs could increase over the long term.
Statement of Operations Analysis
Consolidated Results of Operations
Our consolidated results of operations include the results of Berry beginning December 18, 2025, the closing date of the Berry Merger. Our consolidated results of operations include the results of Aera beginning July 1, 2024, the closing date of the Aera Merger. For more information on the Berry Merger and the Aera Merger, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 2 Business Combinations. The Aera Merger and related integration activities significantly impacted the comparability of our financial results for the year ended December 31, 2025 compared to the prior year.
For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the 2026 Senior Notes Indenture, 2029 Senior Notes Indenture and 2034 Senior Notes Indenture, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 18 Condensed Consolidating Financial Information.
Year Ended December 31, 2025 vs. 2024
The following table presents our consolidated operating revenues:
|
Year ended December 31, |
Year ended December 31, |
||||||||||
| 2025 | 2024 | ||||||||||
| (in millions) | |||||||||||
|
Oil, natural gas and natural gas liquids sales
|
$ | 2,910 | $ | 2,537 | |||||||
|
Net gain from commodity derivatives
|
266 | 241 | |||||||||
|
Revenue from marketing of purchased commodities
|
238 | 235 | |||||||||
|
Electricity revenue
|
233 | 159 | |||||||||
|
Other revenue
|
22 | 26 | |||||||||
| Total operating revenues | $ | 3,669 | $ | 3,198 | |||||||
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 $2,910 million for the year ended December 31, 2025, which is an increase of $373 million from $2,537 million for the year ended December 31, 2024. The following table shows changes in oil, natural gas and natural gas liquids sales for the year ended December 31, 2025 compared to the year ended December 31, 2024:
| Oil | NGLs | Natural Gas | Total | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
|
Year ended December 31, 2024
|
$ | 2,255 | $ | 186 | $ | 96 | $ | 2,537 | |||||||||||||||
| Changes in realized prices | (304) | (14) | 24 | (294) | |||||||||||||||||||
|
Changes in production and other
|
696 | (8) | - | 688 | |||||||||||||||||||
|
Changes in intersegment revenues
|
- | - | (21) | (21) | |||||||||||||||||||
|
Year ended December 31, 2025
|
$ | 2,647 | $ | 164 | $ | 99 | $ | 2,910 | |||||||||||||||
Note: See Results of Our Oil and Natural Gas Operations Production for volumes by commodity type andPrices and Realizationsfor index and average realized prices for each period.
Net gain from commodity derivatives- We report gains and losses on our derivative contracts related to our oil production and marketing activities in operating revenue. Net gain from commodity derivatives was $266 million for the year ended December 31, 2025 compared to a net gain of $241 million for the year ended December 31, 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:
|
Year ended December 31, |
Year ended December 31, |
||||||||||
| 2025 | 2024 | ||||||||||
| (in millions) | |||||||||||
| Non-cash commodity derivative gain | $ | 225 | $ | 274 | |||||||
|
Net proceeds (settlements) and premium amortization
|
41 | (33) | |||||||||
|
Net gain from commodity derivatives
|
$ | 266 | $ | 241 | |||||||
Electricity revenue -Electricity revenue increased by $74 million to $233 million during the year ended December 31, 2025 compared to $159 million for the year ended December 31, 2024. This increase was primarily a result of higher pricing from resource adequacy contracts and additional electricity sales in 2025 as a result of scheduled maintenance and unplanned downtime at our Elk Hills power plant in 2024.
The following table presents our consolidated operating and non-operating expenses and income for the years ended December 31, 2025 and 2024:
|
Year ended December 31, |
Year ended December 31, |
||||||||||
| 2025 | 2024 | ||||||||||
| (in millions) | |||||||||||
| Operating expenses | |||||||||||
|
Operating costs
|
1,252 | 966 | |||||||||
| General and administrative expenses | 333 | 321 | |||||||||
| Depreciation, depletion and amortization | 511 | 388 | |||||||||
|
Asset impairment
|
59 | 14 | |||||||||
| Taxes other than on income | 242 | 242 | |||||||||
| Costs related to marketing of purchased commodities | 182 | 193 | |||||||||
| Electricity generation expenses | 38 | 40 | |||||||||
| Transportation costs | 79 | 81 | |||||||||
| Accretion expense | 114 | 87 | |||||||||
| Net loss on natural gas purchase derivatives | 50 | 30 | |||||||||
| Measurement period adjustments, net | 1 | (12) | |||||||||
| Other operating expenses, net | 209 | 239 | |||||||||
| Total operating expenses | $ | 3,070 | $ | 2,589 | |||||||
|
(Loss) gain on asset divestitures
|
(1) | 11 | |||||||||
|
Operating income
|
598 | 620 | |||||||||
| Non-operating (expenses) income | |||||||||||
|
Interest and debt expense, net
|
(106) | (87) | |||||||||
|
Loss on early extinguishment of debt
|
(1) | (5) | |||||||||
|
Equity loss from unconsolidated subsidiaries
|
(4) | (10) | |||||||||
|
Other non-operating income (expense), net
|
15 | (2) | |||||||||
|
Income before income taxes
|
502 | 516 | |||||||||
|
Income tax provision
|
(139) | (140) | |||||||||
|
Net income
|
$ | 363 | $ | 376 | |||||||
Operating costs- The following table presents our operating costs for the years ended December 31, 2025 and December 31, 2024:
|
Year ended December 31, |
Year ended December 31, |
||||||||||
| 2025 | 2024 | ||||||||||
| (in millions) | |||||||||||
| Energy operating costs | $ | 374 | $ | 279 | |||||||
| Gas processing costs | 19 | 16 | |||||||||
| Non-energy operating costs | 859 | 671 | |||||||||
|
Operating costs
|
$ | 1,252 | $ | 966 | |||||||
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 generate electricity used in our 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 year ended December 31, 2025 were $374 million, which was an increase of $95 million from $279 million for the year ended December 31, 2024. Approximately $94 million of this increase is related to the addition of the Aera fields for the full year of 2025 compared to only six months in 2024. The remaining increase primarily related to higher energy prices partially offset by savings related to the additional supply of electricity generated at our Elk Hills power plant which is used at our Elk Hills field in 2025. During the year ended December 31, 2024, our Elk Hills power plant experienced unplanned downtime and scheduled maintenance resulting in lower electricity generation available the Elk Hills field. For more information on our natural gas market prices, see Segment Results of Oil and Natural Gas Operations, Production, Prices and Realizations below.
Non-energy operating costs- Non-energy operating costs for the year ended December 31, 2025 were $859 million, which was an increase of $188 million from $671 million for the year ended December 31, 2024. Of this increase, $191 million related to the operation of the Aera fields for the full year ended December 31, 2025 compared to only six months in 2024. This increase was partially offset by lower maintenance activity during the year ended December 31, 2025 as compared to 2024.
General and administrative expenses- General and administrative expenses were $333 million for the year ended December 31, 2025, which was an increase of $12 million from $321 million for the year ended December 31, 2024. The increase was primarily a result of additional compensation-related expense and other corporate expenses resulting from the Aera Merger.
Depreciation, depletion and amortization - Depreciation, depletion and amortization increased $123 million to $511 million for the year ended December 31, 2025 from $388 million for the same prior year period. The increase was primarily the result of the addition of the Aera assets included in the full year ended December 31, 2025.
Asset impairment - We recognized a $59 million asset impairment during the year ended December 31, 2025 of which $57 million related to the write-down of our proved natural gas properties in the Sacramento basin. For more information on the impairment of natural gas properties in the Sacramento basin, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 3 Property, Plant and Equipment. During the year ended December 31, 2024, we recognized a $14 million impairment primarily related to excess and obsolete materials and supplies related to our oilfield operations. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 1 Nature of Business, Summary of Significant Accounting Policies and Other for more information.
Accretion expense- Accretion expense was $114 million for the year ended December 31, 2025, which was an increase of $27 million from $87 million for the year ended December 31, 2024. The increase was primarily due to the addition of the Aera asset retirement liability related to the Aera fields in connection with the Aera Merger.
Net loss on natural gas purchase derivatives- Net loss on natural gas purchase derivatives was $50 million for the year ended December 31, 2025. For the same prior year period, we recognized a net loss of $30 million. 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. We added derivative positions held by Berry at December 18, 2025 and recognized a change in fair value between legal close and December 31, 2025. Gains and losses from our commodity derivative contracts are shown in the table below. For more information on our derivatives, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 7 Derivatives.
|
Year ended December 31, |
Year ended December 31, |
||||||||||
| 2025 | 2024 | ||||||||||
| (in millions) | |||||||||||
|
Non-cash loss (gain) on natural gas purchase derivatives
|
$ | 24 | $ | (2) | |||||||
|
Settlements
|
26 | 32 | |||||||||
|
Net loss on natural gas purchase derivatives
|
$ | 50 | $ | 30 | |||||||
Measurement period adjustments, net - Measurement period adjustments relate to changes made to the initial accounting for assets acquired and liabilities assumed in the Aera Merger. The adjustments for the year ended December 31, 2025 included adjustments to depreciation, depletion and amortization expense resulting from changes to the initial purchase price allocation. The adjustments for the year ended December 31, 2024 related to accretion expense related to asset retirement obligations and depreciation, depletion and amortization expense resulting from changes to the initial purchase price allocation.
Other operating expenses, net- Other operating expenses, net decreased $30 million to $209 million for the year ended December 31, 2025 compared to $239 million for the year ended December 31, 2024.
For the years ended December 31, 2025 and 2024, other operating expenses, net includes the following:
|
Year ended December 31, |
|||||||||||
| 2025 | 2024 | ||||||||||
| (in millions) | |||||||||||
|
Carbon management expenses(a)
|
$ | 54 | $ | 56 | |||||||
|
Transaction and integration costs
|
30 | 57 | |||||||||
|
Incremental energy costs due to downtime at our Elk Hills power plant
|
4 | 50 | |||||||||
|
Severance and termination costs
|
20 | 30 | |||||||||
|
Litigation and settlement related expenses(b)
|
26 | 12 | |||||||||
|
Offshore platforms maintenance and abandonment costs
|
19 | 5 | |||||||||
|
Information technology infrastructure
|
13 | - | |||||||||
|
Environmental remediation
|
9 | - | |||||||||
|
All other
|
34 | 29 | |||||||||
|
Total operating expenses, net
|
$ | 209 | $ | 239 | |||||||
(a)Carbon management expenses relates to the development of our carbon management business and includes operating lease costs, payroll costs related to our technical teams and is included in other segment expenses. For more information on our carbon management segment, refer to Part II, Item 8 - Financial Statements and Supplementary Data, Note 16 Segment Information.
(b)See Part II, Item 8 - Financial Statements and Supplementary Data, Note 6 Lawsuits, Claims, Commitments and Contingenciesfor more information on a $25 million payment we made to CalGEM.
(Loss) gain on asset divestitures- Our loss on asset divestitures for the year ended December 31, 2025 was $1 million primarily related to the final purchase price adjustment related to the sale of oil and gas assets located in Ventura. Gain on asset divestitures for the year ended December 31, 2024 was $11 million primarily related to the divestiture of non-core assets and our Ventura divestiture. For more information on our asset divestitures, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 9 Divestitures and Acquisitions.
Interest and debt expense, net - Interest and debt expense, net was $106 million for the year ended December 31, 2025, which was an increase of $19 million from $87 million for the year ended December 31, 2024. The increase was predominately due to higher outstanding debt for the full year ended 2025 compared to 2024. Our 2029 Senior Notes were outstanding for only part of 2024 compared to the full year in 2025, as $600 million was issued in June 2024 and $300 million was issued in August 2024 in a follow-on issuance. Outstanding debt was also higher in 2025 due to the issuance of $400 million of our 2034 Senior Notes completed in October 2025 resulting in increased interest expense. This increase in interest expense was partially offset by lower interest expense resulting from debt repayments, including the redemption of $123 million of our 2026 Senior Notes in February 2025 and the redemption of the remaining $122 million of the 2026 Senior Notes in October 2025, which reduced outstanding principal and related interest expense. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 5 Debt for information on our recent financings.
Other non-operating income (expenses), net- We recognized $15 million other non-operating income during the year ended December 31, 2025 primarily related to actuarial gains on plan assets held in our pension and postretirement benefit plan. During the year ended December 31, 2024, we recognized $2 million other non-operating expense primarily relating to the write-off of financing fees related to a bridge loan we entered into in connection with the Aera Merger which was partially offset by a prior service cost gain on our postretirement benefit plan.
Segment Results of Oil and Natural Gas Operations
The following tables includes financial results and key operating data for our oil and natural gas segment for the years ended December 31, 2025, 2024 and 2023. Our results of operations for the oil and natural gas segment include the financial and operating results of Aera beginning on July 1, 2024, the closing date of the Aera Merger. For more information on the Aera Merger, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 2 Business Combinations.
| Year ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
|
Production and oil and gas segment financial data
|
(in millions, except as otherwise stated)
|
||||||||||||||||
|
Net production sold (MBoe/d)
|
138 | 110 | 86 | ||||||||||||||
|
Total operating revenues
|
$ | 2,967 | $ | 2,572 | $ | 2,172 | |||||||||||
|
Segment profit
|
$ | 688 | $ | 815 | $ | 922 | |||||||||||
|
Items affecting comparability:
|
|||||||||||||||||
|
Asset impairments(a)
|
$ | 57 | $ | 13 | $ | - | |||||||||||
|
Net (loss) gain on asset divestitures(b)
|
$ | (1) | $ | 10 | $ | 32 | |||||||||||
|
Key operating expenses per Boe
|
|||||||||||||||||
| Operating costs | $ | 25.42 | $ | 24.51 | $ | 26.24 | |||||||||||
|
Operating costs, after hedges on purchased natural gas
|
$ | 25.94 | $ | 25.31 | $ | 26.24 | |||||||||||
|
General and administrative expenses(c)
|
$ | 0.85 | $ | 1.07 | $ | 1.34 | |||||||||||
|
Depreciation, depletion and amortization(d)
|
$ | 9.77 | $ | 8.83 | $ | 6.61 | |||||||||||
|
Taxes other than on income
|
$ | 4.03 | $ | 5.16 | $ | 3.61 | |||||||||||
| Field transportation expenses | $ | 0.81 | $ | 0.90 | $ | 0.99 | |||||||||||
(a)Asset impairment for the year ended December 31, 2025 includes the write-down of our proved properties in the Sacramento basin. Asset impairment for the year ended December 31, 2024 related to the write-off of excess and obsolete materials and supplies, generally requisitioned for wells and capitalized as part of drilling and completion activities. The table above excludes asset impairments that were not related to the oil and natural gas segment.
(b)Loss on asset divestitures for the year ended December 31, 2025 related to the sale of our West Montalvo property in Ventura County, California. Gain on asset divestitures for the year ended December 31, 2024 related to the sale of our 0.9-acre Fort Apache real estate property in Huntington Beach, California as well as the remaining portion of our Ventura assets which were classified as held for sale. Gain on asset divestitures for the year ended December 31, 2023 related to the sale of our non-operated interest in the Round Mountain Unit and a non-producing asset in exchange for the assumption of liabilities.
(c)Only includes general and administrative expenses allocated to our oil and natural gas segment.
(d)Excludes depreciation, depletion and amortization related to our corporate assets and Elk Hills power plant.
Production, Prices and Realizations
The amounts in the production tables below show volumes from CRC's operated and non-operated fields for each of the periods presented. These amounts include volumes produced from Berry's operated and non-operated fields during the period from December 18, 2025 through December 31, 2025, and volumes produced from Aera's operated and non-operated fields beginning July 1, 2024.
Net Production Sold
The following table presents our net production sold per day in each of the 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.
| Year ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Oil (MBbl/d) | 109 | 80 | 52 | ||||||||||||||
| NGLs (MBbl/d) | 10 | 10 | 11 | ||||||||||||||
| Natural gas (MMcf/d) | 114 | 117 | 135 | ||||||||||||||
| Total Daily Net Production (MBoe/d) | 138 | 110 | 86 | ||||||||||||||
The following table summarizes the changes to our total daily net production per day for the periods presented:
| Year ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (MBoe/d) | |||||||||||||||||
| Beginning of the year | 110 | 86 | 91 | ||||||||||||||
|
Divestitures(a)
|
- | (1) | - | ||||||||||||||
|
Plant downtime(b)
|
- | (2) | - | ||||||||||||||
|
Acquisitions(c)
|
30 | 34 | - | ||||||||||||||
| PSC effect | 2 | - | 1 | ||||||||||||||
| Natural decline and other | (4) | (7) | (6) | ||||||||||||||
| Total change | 28 | 24 | (5) | ||||||||||||||
| End of the year | 138 | 110 | 86 | ||||||||||||||
(a)See Part II, Item 8 - Financial Statements and Supplementary Data, Note 9 Divestitures and Acquisitionsfor more information. Note that for the year ended December 31, 2023, our divestitures did not have a significant impact on our production volumes because the sale of our non-operated working interest in the Round Mountain Unit closed on December 29, 2023 and we sold a non-producing asset during the year.
(b)Included scheduled maintenance and unplanned downtime at our Elk Hills power plant for the year ended December 31, 2024.
(c)We completed the Aera Merger on July 1, 2024 and the amount of production shown in the table above is averaged over a 12-month period. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 2 Business Combinations for more information.
Prices and Realizations
Our operating results and those of the oil and natural gas industry as a whole are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. The following tables set forth average benchmark prices, average realized prices and price realizations as a percentage of average benchmark prices for our products for the periods indicated below:
| 2025 | 2024 | 2023 | |||||||||||||||||||||||||||||||||
|
Price
|
Realization |
Price
|
Realization |
Price
|
Realization | ||||||||||||||||||||||||||||||
| Oil ($ per Bbl) | |||||||||||||||||||||||||||||||||||
| Brent | $ | 68.22 | $ | 79.84 | $ | 82.22 | |||||||||||||||||||||||||||||
| Realized price without derivative settlements | $ | 66.52 | 98% | $ | 76.92 | 96% | $ | 80.41 | 98% | ||||||||||||||||||||||||||
|
Derivative settlements
|
0.99 | (1.26) | (14.44) | ||||||||||||||||||||||||||||||||
| Realized price with derivative settlements | $ | 67.51 | 99% | $ | 75.66 | 95% | $ | 65.97 | 80% | ||||||||||||||||||||||||||
| WTI | $ | 64.81 | $ | 75.72 | $ | 77.62 | |||||||||||||||||||||||||||||
| Realized price without derivative settlements | $ | 66.52 | 103% | $ | 76.92 | 102% | $ | 80.41 | 104% | ||||||||||||||||||||||||||
| Realized price with derivative settlements | $ | 67.51 | 104% | $ | 75.66 | 100% | $ | 65.97 | 85% | ||||||||||||||||||||||||||
|
Natural Gas Liquids ($ per Bbl)
|
|||||||||||||||||||||||||||||||||||
|
Realized price (% of Brent)
|
$ | 45.30 | 66% | $ | 48.93 | 61% | $ | 48.94 | 60% | ||||||||||||||||||||||||||
|
Realized price (% of WTI)
|
$ | 45.30 | 70% | $ | 48.93 | 65% | $ | 48.94 | 63% | ||||||||||||||||||||||||||
| Natural gas | |||||||||||||||||||||||||||||||||||
|
NYMEX Henry Hub ($/MMBtu)
|
$ | 3.43 | $ | 2.27 | $ | 2.74 | |||||||||||||||||||||||||||||
|
Realized price ($/Mcf)
|
$ | 3.57 | 104% | $ | 2.99 | 132% | $ | 8.59 | 314% | ||||||||||||||||||||||||||
Oil- Brent and our average realized price without derivative settlements were lower for the year ended December 31, 2025 compared to the same prior year period largely due to an increase in global oil production beginning in later 2025 as both OPEC+ and non-OPEC countries increased production.
NGLs- Prices for natural gas liquids were lower for the year ended December 31, 2025 compared to the prior year which is consistent with broader declines in oil commodity prices. The California market continued to carry a premium as compared to other markets in 2025.
Natural Gas- Average realized prices for our natural gas during the year ended December 31, 2025 were higher than the year ended December 31, 2024 as demand for U.S. natural gas reached record levels.
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, and did not have any revenue for the years ended December 31, 2025, 2024 or 2023. We recently completed construction of our first carbon capture project at our cryogenic gas processing facility and expect first injection in spring 2026, subject to commissioning and final regulatory approval. We define carbon management expense to be our direct operating costs to run our carbon management segment.
The following tables include results for our carbon management segment, excluding unallocated corporate expenses for the years ended December 31, 2025, 2024 and 2023.
| Year ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
|
(in millions, except as otherwise stated)
|
|||||||||||||||||
|
Segment loss
|
$ | (86) | $ | (94) | $ | (66) | |||||||||||
|
Items affecting comparability:
|
|||||||||||||||||
|
Asset impairments(a)
|
$ | 2 | $ | 1 | $ | 3 | |||||||||||
(a)Asset impairment for the years ended December 31, 2025, 2024 and 2023 related to land acquired for our carbon management activities. The table above excludes asset impairments that were not related to the carbon management segment.
We recognized our share of losses for the years ended December 31, 2025, 2024 and 2023 related to our Carbon TerraVault joint venture, as shown in the table below. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 4 Investments and Related Party Transactionsfor more information on our Carbon TerraVault joint venture. Carbon management expense and general and administrative expense for the years ended December 31, 2025, 2024 and 2023 are included in the table below.
| Year ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
|
(in millions)
|
|||||||||||||||||
|
Carbon management expenses
|
$ | 54 | $ | 56 | $ | 37 | |||||||||||
|
Segment general and administrative expense
|
$ | 13 | $ | 15 | $ | 12 | |||||||||||
|
Loss from investment in the Carbon TerraVault JV
|
$ | 6 | $ | 12 | $ | 9 | |||||||||||
Carbon management expenses decreased in 2025 compared to 2024 as a result of lower community development activities which were partially offset by higher costs related to feasibility studies that were undertaken.
Liquidity and Capital Resources
Liquidity
Our primary sources of liquidity and capital resources are cash flows from operations, available cash and cash equivalents, proceeds from the issuance of our senior notes 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 year ended December 31, 2025 were for capital investments, redemption of our 2026 Senior Notes, repurchase of our common stock, and payment of dividends.
The following table summarizes our liquidity:
| December 31, 2025 | |||||
| (in millions) | |||||
|
Available cash and cash equivalents(a)
|
$ | 117 | |||
| Revolving Credit Facility: | |||||
| Borrowing capacity | 1,460 | ||||
| Outstanding letters of credit | (176) | ||||
| Availability | $ | 1,284 | |||
| Liquidity | $ | 1,401 | |||
(a)Excludes restricted cash of $15 million.
Derivatives
Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow, and the inverse applies during periods of rising commodity 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 upon 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 for the year ended December 31, 2025.
Refer to Part II, Item 8 - Financial Statements and Supplementary Data, Note 7 Derivatives for more information on our open derivative contracts as of December 31, 2025 and Note 5 Debtfor more information on the hedging requirements included in our Revolving Credit Facility.
Long-Term Debt
Our long-term debt consists of borrowings and indebtedness under our Revolving Credit Facility, 2029 Senior Notes and 2034 Senior Notes. Our previously issued 2026 Senior Notes were redeemed in full in 2025. For more information regarding our Revolving Credit Facility, 2026 Senior Notes, 2029 Senior Notes and 2034 Senior Notes, refer to Part II, Item 8 - Financial Statements and Supplementary Data, Note 5 Debt.
Revolving Credit Facility
On April 26, 2023, we entered into an Amended and Restated Credit Agreement (Revolving Credit Facility) with Citibank, N.A., as administrative agent, and certain other lenders, which amended and restated in its entirety the prior credit agreement dated October 27, 2020. As of December 31, 2025, we were in compliance with all of the covenants of our Revolving Credit Facility. Refer to Part II, Item 8 - Financial Statements and Supplementary Data, Note 5 Debt for more information on recent amendments to our Revolving Credit Facility.
2034 Senior Notes
On October 8, 2025, we completed an offering of $400 million in an aggregate principal amount of 7.000% senior notes due 2034 (2034 Senior Notes). The terms of the 2034 Senior Notes are governed by the Indenture, dated as of October 8, 2025, by and among us, our subsidiary guarantors and Wilmington Trust, National Association, as trustee (2034 Senior Notes Indenture). The net proceeds of $393 million, after $7 million of debt issuance costs, were used to repay Berry's long-term debt at closing of the Berry Merger.
2029 Senior Notes
On June 5, 2024, we completed an offering of $600 million in aggregate principal amount of 8.25% senior notes due 2029 (2029 Senior Notes). The terms of the 2029 Senior Notes are governed by the Indenture, dated as of June 5, 2024, by and among us, our subsidiary guarantors and Wilmington Trust, National Association, as trustee (2029 Senior Notes Indenture). The net proceeds of $590 million, after $10 million of debt discount and issuance costs, were used along with available cash to repay all of Aera's outstanding debt at closing of the Aera Merger.
On August 22, 2024, we completed a follow-on offering of $300 million in aggregate principal amount of 2029 Senior Notes. The net proceeds from this offering of $298 million, after $3 million of debt premium and $5 million of debt issuance costs, were used to repurchase a portion of our outstanding 2026 Senior Notes as described below. The follow-on 2029 Senior Notes issued on August 22, 2024 are governed by the same indenture as the $600 million of 2029 Senior Notes that were previously issued on June 5, 2024.
2026 Senior Notes
In the year ended December 31, 2025, we redeemed $245 million of our 7.125% Senior Notes due 2026 (2026 Senior Notes) at 100% of the principal amount, resulting in an extinguishment loss in the amount of $1 million for the write-off of unamortized debt issuance costs. Following this redemption, none of our 2026 Senior Notes were outstanding.
In the year ended December 31, 2024, we repurchased $300 million in face value of our 2026 Senior Notes for $303 million resulting in a loss on early extinguishment of debt in the amount of $5 million which includes a $2 million write-off of unamortized debt issuance costs.
Transactions Related to Our Common Stock
The following table is a summary of changes in our outstanding shares of our common stock during the year ended December 31, 2025:
| Common Stock | ||||||||
|
Balance at December 31, 2024
|
91,100,322 | |||||||
|
Issued as part of the Berry Merger(a)
|
5,572,115 | |||||||
|
Shares issued related to the Aera Merger(a)
|
107,265 | |||||||
| Shares issued under ESPP | 60,128 | |||||||
| Shares issued under stock-based compensation arrangements | 478,609 | |||||||
|
Repurchased shares held as treasury stock
|
(3,378,263) | |||||||
| Repurchased shares cancelled | (4,950,000) | |||||||
|
Shares cancelled for taxes(b)
|
(236,011) | |||||||
| Balance at December 31, 2025 | 88,754,165 | |||||||
(a)Refer to Part II, Item 8 - Financial Statements and Supplementary Data, Note 2 Business Combinations for additional information.
(b)In connection with the vesting of equity awards, we withheld and cancelled shares to satisfy applicable tax-withholding requirements.
Common Stock Issued as Part of the Berry Merger
We issued 5,572,115 shares of CRC common stock in connection with the Berry Merger. The shares issued were registered under the Securities Act of 1933, as amended, pursuant to a registration statement on Form S-4 (File No. 333-290871) filed by CRC with the Securities and Exchange Commission on October 14, 2025, which became effective on November 3, 2025.
Dividends
Once declared, dividends are payable to shareholders in cash on a quarterly basis. The actual declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance.
On March 1, 2026, our Board of Directors declared a cash dividend of $0.405 per share of common stock. The dividend is payable to shareholders of record at the close of business on March 13, 2026 and is expected to be paid on March 20, 2026.
We paid the following cash dividends for each of the periods presented.
|
Total Dividend
|
Annual Rate Per Share
|
||||||||||
|
(in millions)
|
($ per share)
|
||||||||||
|
Year ended December 31, 2023
|
$ | 81 | $ | 1.1575 | |||||||
|
Year ended December 31, 2024
|
113 | $ | 1.3950 | ||||||||
|
Year ended December 31, 2025
|
136 | $ | 1.5675 | ||||||||
| $ | 330 | ||||||||||
Share Repurchase Program
Our Board of Directors authorized a Share Repurchase Program to acquire up to $1.78 billion of our common stock through December 31, 2027. This includes a recent increase of $430 million and extension approved by our Board of Directors on February 24, 2026. After the increase and shares repurchased in January 2026, we had approximately $600 million of remaining unused capacity under this program as of February 28, 2026. For additional information, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 19 Subsequent Events.
The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time. The following is a summary of our share repurchases, held as treasury stock, for the periods presented:
| Total Number of Shares Purchased | Dollar Value of Shares Purchased | Average Price Paid per Share | |||||||||||||||
| (number of shares) | (in millions) | ($ per share) | |||||||||||||||
|
Year ended December 31, 2023
|
3,407,655 | $ | 143 | $ | 41.69 | ||||||||||||
|
Year ended December 31, 2024
|
3,649,348 | $ | 192 | $ | 52.12 | ||||||||||||
|
Year ended December 31, 2025
|
8,328,263 | $ | 377 | $ | 45.29 | ||||||||||||
| Inception of Program (May 2021) through December 31, 2025 | 26,841,526 | $ | 1,173 | $ | 43.59 | ||||||||||||
Note: The total value of shares purchased includes approximately $2 million and $1 million in the years ended December 31, 2024 and 2023 related to excise taxes on share repurchases. Excise taxes in 2025 were insignificant and include a reversal for 2024 excise taxes that were no longer due. Commissions paid were not significant in all periods presented.
Uses of Cash
At current commodity prices, we expect to generate operating cash flow to support and invest in our assets as part of our planned 2026 capital program described below. We regularly review our financial position, commodity prices, market conditions and other considerations to evaluate and optimize the deployment of our cash. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.
2026 Capital Program
We expect our total 2026 capital program to range between $430 million and $470 million. Of this amount, $410 million to $435 million is related to our oil and natural gas segment, $12 million to $20 million is for our carbon management segment and $8 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. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 4 Investments and Related Party Transactionsfor more information on our joint venture with Brookfield.
Oil and natural gas segment -With respect to oil and natural gas development, we expect to run a four rig program in 2026. We currently hold the majority of permits necessary to undertake our 2026 capital program. We expect to obtain additional new well permits for the remainder of our 2026 capital program on a timely basis. For more information on permitting, refer to Part I, Item 1 and 2 - Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities.
Carbon management segment - Our 2026 capital for carbon management projects includes approximately $15 million for the completion of the carbon capture project at our cryogenic gas processing facility at Elk Hills. This gas processing facility is adjacent to the 26R storage reservoir held by Carbon TerraVault JV. For more information this project, refer to Part I, Item 1 and 2 - Business and Properties, Carbon Management Segment.
Other Uses of Cash
Other than our 2026 capital program, our expected material uses of cash during 2026 may include, subject to available liquidity, commodity prices, market conditions and other considerations, one or more of the following: (1) operating expenses; (2) dividends, share and debt repurchases; (3) settlements on commodity derivative contracts; (4) income taxes and other taxes not on income; (5) settlement of asset retirement obligations; and (6) costs related to advancing our carbon management activities not included in our capital program, such as employee costs and front-end engineering and design studies.
Our long-term material uses of cash include the following:
•repayment of principal and interest on our 2029 Senior Notes and 2034 Senior Notes (see Part II, Item 8 - Financial Statements and Supplementary Data, Note 5 Debt)
•operating lease liabilities including our commercial office space, fleet vehicles, easements and certain facilities (see Part II, Item 8 - Financial Statements and Supplementary Data, Note 13 Leases)
•obligations associated with our defined benefit and post-employment benefit plans (see Part II, Item 8 - Financial Statements and Supplementary Data, Note 14 Pension and Postretirement Benefit Plans)
•asset retirement obligations over the longer term (see Part II, Item 8 - Financial Statements and Supplementary Data, Note 1 Nature of Business, Summary of Significant Accounting Policies and Other, Asset Retirement Obligations)
We have certain off-balance sheet commitments under contracts, including purchase commitments for goods and services used in the normal course of business such as pipeline transportation capacity, oil and natural gas leases, obligations under long-term service agreements and field equipment. The table below summarizes our undiscounted current and long-term purchase obligations as of December 31, 2025.
|
One Year or Less
|
More Than One Year
|
Total
|
|||||||||||||||
| (in millions) | |||||||||||||||||
|
Oil and gas leases, surface easements and pipeline right-of-way(a)
|
$ | 1 | $ | 2 | $ | 3 | |||||||||||
|
Oil and gas transportation, throughput and storage arrangements(b)
|
19 | 72 | 91 | ||||||||||||||
|
Software licenses and other contracts
|
48 | 58 | 106 | ||||||||||||||
|
Contracts related to our carbon management segment(c)
|
1 | - | 1 | ||||||||||||||
| Total | $ | 69 | $ | 132 | $ | 201 | |||||||||||
(a)Oil and natural gas leases reflect obligations for fixed payments under our contracts.
(b)Purchase obligations for pipeline capacity include ship or pay arrangements that are based on contractual volumes and current market rates for firm transportation capacity during the contract period.
Cash Flow Analysis
Cash flows from operating activities- Our net cash provided by operating activities is sensitive to many variables, particularly changes in commodity prices. Commodity price movements may also lead to changes in other variables in our business, including adjustments to our capital program. We experienced peak pricing for resource adequacy contracts in 2025 as compared to 2024. However, market prices for 2026 resource adequacy contracts declined due to growth in available resource adequacy-eligible capacity in the California market. As a result, we expect that our 2026 revenues from resource adequacy contracts will decrease between $125 million to $135 million in 2026 as compared to 2025.
Our operating cash flow for the year ended December 31, 2025 was $865 million, which was an increase of $255 million, from $610 million for the year ended December 31, 2024. The increase was primarily driven by increased production after the Aera Merger which occurred on July 1, 2024. For the year ended December 31, 2025 we produced 138 MBoe/d, which was an increase of 37 MBoe/d from 110 MBoe/d for the year ended December 31, 2024. Our oil production increased to 109 MBbl/d for the year ended December 31, 2025 compared to 80 MBbl/d for the year ended December 31, 2024. Increases in production were partially offset by lower realized oil prices in 2025. Our average realized price for oil without the effects of derivative settlements decreased by $10.40 to $66.52 for the year ended December 31, 2025 compared to $76.92 for the same prior year period. For more information on our production and price changes, see Segment Results of Oil and Natural Gas Operationsabove.
Settlement proceeds from our derivative contracts increased $79 million from $64 million settlement payments for the year ended December 31, 2024 to $15 million settlement proceeds for the year ended December 31, 2025. For more information on our derivative contracts see, Part II, Item 8 - Financial Statements and Supplementary Data, Note 7 Derivatives.
Operating costs and general and administrative expenses increased in 2025 as compared to 2024 primarily due to the addition of Aera's operations for the full year. As a result, we had higher compensation-related costs and additional costs related to surface maintenance, energy and purchase injectant.
Cash flows used in investing activities- The following table provides a comparative summary of net cash used in investing activities:
| Year ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (in millions) | |||||||||||
|
Capital investments
|
$ | (322) | $ | (255) | |||||||
|
Changes in accrued capital investments
|
35 | 29 | |||||||||
|
Proceeds from asset divestitures
|
8 | 15 | |||||||||
|
Purchase of a business, net of cash acquired
|
(440) | (853) | |||||||||
|
Asset acquisitions
|
- | (6) | |||||||||
|
Other, net
|
(6) | (7) | |||||||||
| Net cash used in investing activities | $ | (725) | $ | (1,077) | |||||||
For the years ended December 31, 2025 and 2024, purchase of a business, net of cash acquired includes our investing activities related to the Berry Merger and the Aera Merger, respectively. In connection with the Berry Merger, we repaid $449 million of Berry's outstanding long-term debt and acquired cash of $12 million (after a $3 million payment for settlement of certain stock-based compensation awards). Additionally, we increased our 2025 capital program following the Aera Merger. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 2 Business Combinations for more information on these transactions.
Proceeds from asset divestitures for the year ended December 31, 2025 primarily included the sale of properties for carbon management activities. Proceeds from asset divestitures for the year ended December 31, 2024 included the sale of our 0.9-acre Fort Apache real estate property in Huntington Beach, California as well as the remaining portion of our Ventura assets which were classified as held for sale. In the year ended December 31, 2024, the acquisitions shown in the table above related to purchasing storage reservoirs for our carbon management segment. Part II, Item 8 - Financial Statements and Supplementary Data, Note 9 Divestitures and Acquisitions for more information on our divestitures and acquisitions.
Cash flows used in financing activities- The following table provides a comparative summary of net cash used in financing activities:
| Year ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (in millions) | |||||||||||
|
Proceeds from Revolving Credit Facility
|
$ | 220 | $ | 30 | |||||||
|
Repayments of Revolving Credit Facility
|
(220) | (30) | |||||||||
|
Proceeds from 2029 Senior Notes, net
|
- | 888 | |||||||||
|
Proceeds from 2034 Senior Notes, net
|
393 | - | |||||||||
|
Repurchases of common stock(a)
|
(377) | (192) | |||||||||
| Common stock dividends | (136) | (113) | |||||||||
|
Dividend equivalents on equity-settled awards
|
(3) | (4) | |||||||||
| Issuance of common stock | 3 | 2 | |||||||||
|
Bridge loan commitment costs
|
- | (5) | |||||||||
|
Debt redemption
|
(245) | (303) | |||||||||
|
Debt amendment costs
|
(3) | (18) | |||||||||
|
Stock warrants exercised
|
- | 130 | |||||||||
|
Shares cancelled for taxes
|
(12) | (42) | |||||||||
|
Net cash (used in) provided by financing activities
|
$ | (380) | $ | 343 | |||||||
(a)The total value of shares purchased reported on our statement of cash flows includes approximately $2 million in the year ended December 31, 2024, related to excise taxes on share repurchases. Excise taxes in 2025 were insignificant and include a reversal for 2024 excise taxes that were no longer due. Commissions paid on share repurchases were not significant in all periods presented.
As noted above in Long-Term Debt, in October 2025, we completed an offering of $400 million in aggregate principal amount of our 7.000% 2034 Senior Notes. We also redeemed $245 million of our 2026 Senior Notes at 100% of the principal amount. In the year ended December 31, 2024, we completed an initial offering and a follow-on offering for our 2029 Senior Notes and we repurchased $300 million in face value of our 2026 Senior Notes at a premium. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 5 Debt for more information on our financing arrangements.
Cash used for repurchases of our common stock under our Share Repurchase Program increased in 2025 as compared to 2024. Additionally, our Board of Directors increased the quarterly dividend rate on our common stock during 2025. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 11 Stockholders' Equity for more information on our Share Repurchase Program and cash dividends.
Divestitures and Acquisitions
From time to time, we review our extensive portfolio of assets for potential divestitures. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 9 Divestitures and Acquisitionsfor more information.
Lawsuits, Claims, Commitments and Contingencies
We are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at December 31, 2025 and 2024 were not material to our consolidated balance sheets as of such dates.
In October 2020, Signal Hill Services, Inc. defaulted on its decommissioning obligations associated with two offshore platforms. The Bureau of Safety and Environmental Enforcement (BSEE) determined that former lessees, including our former parent, Occidental Petroleum Corporation (Oxy) with a 37.5% share, are responsible for accrued decommissioning obligations associated with these offshore platforms. Oxy sold its interest in the platforms approximately 30 years ago and it is our understanding that Oxy has not had any connection to the operations since that time and challenged BSEE's order. Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy. In September 2021, we accepted the indemnification claim from Oxy and we are challenging the order from BSEE. In March 2024, we entered into a cost sharing agreement with former lessees to share in ongoing maintenance costs during the pendency of the challenge to the BSEE order. In September 2025, the parties amended the cost sharing agreement to include well abandonment work. As of December 31, 2025, we recognized a liability of $12 million, included in accrued liabilities in our consolidated balance sheet related to this abandonment work.
We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined.
See Part II, Item 8 - Financial Statements and Supplementary Data, Note 6 Lawsuits, Claims, Commitments and Contingencies.
Critical Accounting Estimates
Our critical accounting estimates that could result in a material impact to the consolidated financial statements due to the levels of subjectivity and management judgment include the following:
| Title | Description | Estimation and Uncertainties | Sensitivities | |||||||||||||||||
| Oil and Natural Gas Properties |
The carrying value of our property, plant and equipment represents the costs incurred to acquire or develop the asset, including any asset retirement obligations, net of accumulated depreciation, depletion and amortization. For assets acquired in a business combination, PP&E cost is based on fair values at the acquisition date. We use the successful efforts method of accounting for our oil and natural gas producing activities. Under this method, we capitalize the cost of acquiring properties, development costs and the costs of drilling successful exploration wells.
The estimated amount of proved reserve volumes is used as the basis for recording depletion expense. We determine depletion on our oil and natural gas producing properties using the unit-of-production method. Under this method, acquisition costs are amortized based on total proved oil and gas reserves and capitalized development and successful exploration costs are depleted based on proved developed oil and natural gas reserves.
Accounting for business combinations requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill. The preliminary fair value of Berry's proved reserves acquired in the acquisition approximated $637 million. We do not have significant capitalized costs related to unproved properties and have not identified significant unproved properties as a result of the acquisition of Berry.
|
The determination of quantities of proved reserves is a highly technical process performed by our engineers and geoscientists. The analysis is based on drilling results, reservoir performance, subsurface interpretation and future development plans. Production rate forecasts are primarily derived from estimates from decline-curve analysis and type-curve analysis. Secondary inputs may include material balance calculations, which consider the volumes of substances replacing the volumes produced and associated reservoir pressure changes. Additional inputs may also include seismic analysis and computer simulations of reservoir performance. These field-tested technologies have demonstrated reasonably certain results with consistency and repeatability in the formations being evaluated or in analogous formations. The data for a given reservoir may also change over time as a result of numerous factors including, but not limited to, additional development activity and future development costs, production history and continuous reassessment of the viability of future production volumes under varying economic conditions.
Several other factors could change our proved oil and gas reserves including changes in energy costs, inflation, deflation and the political and regulatory environment, all of which are beyond our control.
We estimated the fair value of Berry's proved reserves at the acquisition date using the expected present value of discounted future cash flows, on an after-tax basis, and applying a reasonable discount rate. We have used all available information to make a fair value determination, including assistance from third-party valuation experts. The assumptions used are believed to be reasonable but could change. This would have the effect of increasing or decreasing the amount of DD&A we recognized on acquired assets.
|
Our total proved reserves were 654 MMBoe and our total proved developed reserves were 541 MMBoe at December 31, 2025. We estimate our 2026 depletion rate for oil and natural gas producing properties using the unit-of-production method will be approximately $9/Boe. A 5% change in our reserves would increase or decrease this DD&A rate by approximately $0.47/Boe.
|
|||||||||||||||||
| Title | Description | Estimation and Uncertainties | Sensitivities | |||||||||||||||||
| Asset Retirement Obligations |
Our asset retirement obligations relate to the plugging and abandonment of oil and natural gas wells and facilities used in the oil and natural gas segment.
We determine our asset retirement obligation, including the obligations related to Berry's assets we acquired, by calculating the present value of estimated future cash outflows related to the abandonment obligation.
The asset retirement cost is capitalized as part of the carrying amount of the related long-lived asset or included in the fair value estimate in a business combination. In periods subsequent to initial measurement, the asset retirement cost is depreciated using the unit-of-production method, while increases in the ARO liability resulting from the passage of time (accretion expense) is included in operating expenses on our consolidated statements of operations.
|
The recognition of an asset retirement obligation requires us to make assumptions including an estimate of future abandonment costs and inflation rates, timing of activity and our credit-adjusted discount rate among others. Changes in the legal, regulatory and political environment could also affect our estimated future cash outflows. |
As of December 31, 2025 and 2024, we had asset retirement obligations of $1,033 million and $1,129 million, respectively.
A 1% increase in the inflation rate would increase our liability by $94 million and a 1% decrease in the inflation rate would decrease our liability by $89 million as of December 31, 2025.
|
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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. Additionally, the information in this report contains forward-looking statements related to the recently announced Aera merger.
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 and Ukraine and geopolitical uncertainty in the Middle East and Venezuela;
•the ability to successfully execute integration efforts in connection with the Berry 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;
•refinery closures and reductions in pipeline transportation capacity;
•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 the ability and financial resources to execute our capital plan in a timely manner;
•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 MOUs and CDMAs to definitive agreements and enter into other offtake agreements;
•our ability to grow and develop our carbon management segment and achieve projected injection and storage rates;
•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; and
•other factors discussed in Part I, Item 1A - Risk Factors.
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 March 02, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on March 02, 2026 at 21:36 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]