California Resources Corp
For the period ended Sep 30, 2025. Filed Nov 5, 2025.
View on SEC.govAbout this filing
A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Sep 30, 2025 · Filed Nov 5, 2025
CRC$46.96+3.0%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-06-30; filed 2025-08-06.
0001609253-25-000069
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-09-30; filed 2025-11-05.
0001609253-25-000090
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 166 previous paragraphs and 193 current paragraphs.
93 unchanged; 53 reworded; 45 added; 19 removed; 1 previous and 2 current paragraphs rearranged.
Tables are not compared: 20 previous and 24 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (45)
Current report
Pending Berry Merger
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
Recent Legislation
Current report
Senate Bill 237 (Oil and Gas Permitting)
Current report
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.
Current report
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.
Current report
Assembly Bill 1207 (Cap-and-Invest Extension)
Current report
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.
Current report
Senate Bill 614 (Carbon Dioxide Pipeline Regulation)
Current report
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.
Current report
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.
Current report
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 Programfor more information.
Current report
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.
Current report
Operating costs— The following table presents our operating costs for the three months ended September 30, 2025 and June 30, 2025:
Current report
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:
Current report
Operating costs —The following table presents our operating costs for the nine months ended September 30, 2025 and September 30, 2024.
Current report
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 million for 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.
Current report
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 million from$445 million for 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.
Current report
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:
Current report
(b)Includes general and administrative expenses allocated to our oil and natural gas segment.
Current report
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.
Current report
2034 Senior Notes
Current report
See Part I, Item 1 – Financial Statements, Note 16 Subsequent Eventsfor information on our 2034 Senior Notes.
Current report
See Part I, Item 1 – Financial Statements, Note 4 Debtand Note 16 Subsequent Eventsfor information on the redemption of our 2026 Senior Notes.
Current report
Share Repurchase Program
Current report
Capital Program
Current report
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.
Current report
•the expected timing and resumption of the issuance of well permits following the enactment of SB 237;
Current report
•transaction costs;
Current report
•unknown liabilities
Current report
•the risk that any announcements relating to the Berry Merger could have adverse effects on the market price of our common stock;
Current report
•the ability to successfully integrate Berry;
Current report
•the ability to achieve projected synergies from the Berry Merger or it may take longer than expected to achieve synergies;
Current report
•risks related to financial community and rating agency perceptions of us and our business, operations, financial condition and the industry in which we operate;
Showing the first 40 of 45 passages. Open the source sections for the rest.
Removed paragraphs (19)
Previous report
During 2025, Brent prices were negatively affected by a succession of announcements by OPEC+ of its intention to return offline production to market at a much quicker pace than previously anticipated and concern over the state of global trade following a series of tariff announcements. Prices slightly increased in June 2025 as tensions between Iran and Israel became overtly military in nature and a concern developed that petroleum flowing through the Persian Gulf — and through the Strait of Hormuz, in particular — could ultimately be impacted.
Previous report
Collectively, these factors introduced significant oil price volatility with Brent crude oil prices fluctuating between a low of approximately $60 per barrel in early May and a high of approximately $80 per barrel in mid-June.
Previous report
During the first half of 2025, we have received total well permits for 139 workovers, 105 sidetracks and 4 deepenings. We have not received any permits for new wells in 2025.
Previous report
We currently hold sufficient permits to maintain our existing two drilling rig capital program throughout 2025. We also have the requisite number of permits in hand to run one active drilling rig throughout 2026.
Previous report
On June 26, 2025, the Kern County Board of Supervisors certified a revised Environmental Impact Report (EIR) and approved an ordinance that authorizes the development of oil and natural gas wells in the county consistent with the revised EIR. Kern County is seeking the Trial Court’s determination that the revised EIR complies with the judgment and order of the Trial Court and decision of the Court of Appeal. After that, the Trial Court could lift the stay, subject to further potential appeals. The timing of when or if the Trial Court will take such action is uncertain. If the stay is lifted and no further stay is issued by the Court of Appeal, new well permitting could resume. However, there is no certainty we will obtain permits on that timeline or at all, or that the Trial Court and Court of Appeal will collectively lift the stay before a final, non-appealable ruling upholding the adequacy of the revised EIR is issued. These developments could further adversely affect our business, results of operations and financial condition.
Previous report
Waste Emissions Charge
Previous report
In May 2025, following a joint resolution of disapproval under the Congressional Review Act, the EPA issued a final rule to remove the Waste Emission Charge (WEC) regulations, originally adopted under the Inflation Reduction Act, from the Code of Federal Regulations. As a result, the fees associated with methane emissions from certain oil and gas facilities that would have been due to the EPA in September 2025 will not be collected. Although the underlying statute still requires a methane charge, An Act to Provide for Reconciliation Pursuant to Title II of H. Con. Res. 14th and commonly referred to as the One Big Beautiful Bill Act, postponed implementation from 2024 to 2034.
Previous report
Water Injection
Previous report
Our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. CalGEM has issued a directive to reduce the injection well pressure in a gradual manner in accordance with a five-year injection reduction work plan. The first phase of reduction commenced July 1, 2024 and a second reduction began in January 2025. The next phase of reduction is currently on hold while we evaluate the impact of the previously implemented reductions together with CalGEM. The work plan may be adjusted and it is difficult to predict with accuracy the impact to production and reserves. However, we continue to estimate a negative impact on production of approximately 1 MBoe/d at the end of the current 5-year work plan. We also estimate that the net present value of our proved developed reserves would be negatively impacted by less than 1%. These estimates could change materially pending the results of future technical audits.
Previous report
General and administrative expenses — General and administrative (G&A) expenses were $79 million for the three months ended June 30, 2025 compared to $72 million for the three months ended March 31, 2025, which was an increase of $7 million. The increase was primarily a result of higher legal expenses and compensation-related expenses during the three months ended June 30, 2025.
Previous report
Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities for the three months ended June 30, 2025 were $41 million, which is a decrease of $9 million from $50 million for the three months ended March 31, 2025. This decrease was primarily due to lower natural gas prices, partially offset by increased volumes of purchased natural gas.
Previous report
Energy operating costs — Energy operating costs for the six months ended June 30, 2025 were$181 million, which was an increase of $87 million from$94 million for the six months ended June 30, 2024. This increase was predominantly due to additional energy costs and natural gas used in our steamflood operations related to the addition of the Aera fields on July 1, 2024. Excluding $94 million related to the operation of the Aera fields, our energy operating costs would have been $87 million for the six months ended June 30, 2025. The decrease was primarily a result of lower energy and natural gas costs in the six months ended June 30, 2025 compared to the same prior year period.
Previous report
Non-energy operating costs— Non-energy operating costs for the six months ended June 30, 2025 were$421 million, which was an increase of$190 million from$231 million for the six months ended June 30, 2024. The increase includes $191 million predominantly related to the addition of the Aera fields on July 1, 2024. Excluding the costs related to the Aera fields, our non-energy operating costs would have been $230 million for the six months ended June 30, 2025, which would be in line with the same prior year period.
Previous report
(b)Excludes unallocated general and administrative expenses.
Previous report
Natural Gas — Natural gas prices decreased for the three months ended June 30, 2025 compared to the three months ended March 31, 2025 driven by seasonal demand changes and the effects of significant storage volumes. Natural gas prices increased for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 driven by colder, late winter temperatures in early 2025.
Previous report
We have taken steps to reduce headcount as part of the integration process following the Aera Merger. We initiated these workforce reductions to align the size and composition of our workforce with expected future operating and capital plans. Employee severance and related costs are included in other operating expenses, net on our condensed consolidated statement of operations.
Previous report
On July 4, 2025, An Act to Provide for Reconciliation Pursuant to Title II of H. Con. Res. 14th and commonly referred to as the One Big Beautiful Bill Act was signed into law. This law contains several legislative changes including the reinstatement of full expensing for qualified assets placed in service after January 19, 2025. This law also reinstated the expensing all domestic research and development costs, including favorable transition rules, and increases the limitation on the amount of annual business interest expense which can be deducted each year. We expect these legislative changes will reduce our U.S. federal cash tax obligation by approximately $35 million in 2025 and the amount of U.S. federal taxes we would have otherwise owed in future years.
Previous report
See Part I, Item 1 – Financial Statements, Note 4 Debtfor information on a partial redemption of our 2026 Senior Notes.
Previous report
2025 Capital Program
Reworded paragraphs (53)
Previous wording
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 may fluctuate significantly as a result of numerous market-related variables. These and other factors make it challenging to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil and natural gas prices may affect the quantities of oil and natural gas reserves 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.
Current wording
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.
Previous wording
We continued to experience relatively flat pricing from our suppliers in the first half of 2025 as compared to the prior year. Tariff policy changes by the U.S. government for both country of origin and material type remains uncertain. The United States recently expanded tariff rates on imported goods including a 50% tariff on the steel and aluminum value of imported products. These expanded tariff rates, if sustained, could increase our cost of oilfield goods and expand delivery lead times over the longer term. We have taken measures to limit the effects of 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 execution 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 continue to expect minimal impact of tariffs in our supply chain in 2025. Assuming the current tariff regime remains in place or is expanded, our inventory, capital and operating costs could increase over the long-term.
Current wording
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.
Previous wording
In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025. Additionally, 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. Historically, we have sold a portion of our crude oil to these refineries. Assuming both refineries were to cease operations, there will be six remaining major petroleum refineries in California, each of which have a refining capacity greater than 75,000 barrels per day. We expect this would leave California with approximately 1.3 million barrels per day of remaining major refining capacity, which is more than four times the amount of crude oil produced in California in 2024. As a result of this and given the considerable flexibility we have in marketing our production, we do not expect the cessation of operations at these refineries, should they occur, will affect our ability to market our crude oil production. While these announcements have had no impact on our price realizations thus far, fewer refineries in California have the potential to impact our future price realizations.
Current wording
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.
Previous wording
During the three months ended June 30, 2025, we received well permits for 86 workovers and 84 sidetracks. The rate at which CalGEM issued permits for workovers and sidetracks during this period continued to increase relative to the three months ended March 31, 2025.
Current wording
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.
Previous wording
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.
Current wording
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 Permitting in our 2024 Annual Report.
Previous wording
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 Aera Merger, see Part I, Item 1 – Financial Statements, Note 2 Aera Merger. The Aera Merger and related transactions have significantly impacted the comparability of our financial results for the six months ended 2024.
Current wording
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.
Previous wording
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 $702 million for the three months ended June 30, 2025, which is a decrease of $112 million compared to $814 million for the three months ended March 31, 2025.
Current wording
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.
Previous wording
Net 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 gain from commodity derivatives was $157 million for the three months ended June 30, 2025 compared to a net gain of $6 million for the three months ended March 31, 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:
Current wording
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:
Previous wording
Electricity revenue — Electricity revenue increased by $36 million to $58 million for the three months ended June 30, 2025 compared to $22 million for the three months ended March 31, 2025. This increase was primarily a result of higher resource adequacy sales driven by increased seasonal pricing for the three months ended June 30, 2025 compared to the three months ended March 31, 2025, as well as downtime for maintenance that primarily impacted the three months ended March 31, 2025.
Current wording
Electricity revenue — Electricity revenue increased by $43 million to$101 million for 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.
Previous wording
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. 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. There is no internal allocation of the costs to produce steam from the power plant 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
Current wording
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.
Previous wording
Energy operating costs — Energy operating costs for the three months ended June 30, 2025 were $78 million, which was a decrease of $25 million from $103 million for the three months ended March 31, 2025. This decrease was primarily due to lower prices and lower volumes ofnatural gas used in our steamflood operations. For more information on natural gas market prices, see Prices and Realizations below.
Current wording
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 andnatural gas used in our steamflood operations.
Previous wording
Taxes other than on income — Taxes other than on income for the three months ended June 30, 2025 were $47 million, which was a decrease of $23 million from $70 million for the three months ended March 31, 2025. The decrease was primarily due to an adjustment to the production tax rate. We also had lower greenhouse gas expense based on market prices.
Current wording
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.
Previous wording
Other operating expenses, net — Other operating expenses, net increased $32 million to $65 millionfor the three months ended June 30, 2025 compared to $33 million for the three months ended March 31, 2025. For the three months ended June 30, 2025 and March 31, 2025, other operating expenses, net includes the following:
Current wording
Other operating expenses, net — Other operating expenses, net decreased $36 million to $29 millionfor 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:
Previous wording
Income taxes – The income tax provision for the three months ended June 30, 2025 was $70 million (representing an effective tax rate of 29%), compared to a provision of $47 million (representing an effective tax rate of 29%) for the three months ended March 31, 2025. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes.
Current wording
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.
Previous wording
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 $1,516 million for the six months ended June 30, 2025, which is an increase of $675 million compared to $841 million for the six months ended June 30, 2024.
Current wording
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.
Previous wording
The following table shows changes in oil, natural gas and natural gas liquids sales for the six months ended June 30, 2025 compared to the six months ended June 30, 2024.
Current wording
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.
Previous wording
(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 Aera Mergerfor additional information.
Current wording
(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 Combinationsfor additional information.
Previous wording
Net gain (loss) 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 $163 million for the six months ended June 30, 2025 compared to a net loss of $66 million for the six months ended June 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:
Current wording
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:
Previous wording
Electricity revenue — Electricity revenue increased by $29 million to $80 million for the six months ended June 30, 2025 compared to $51 million for the six months ended June 30, 2024. This increase was primarily a result of higher pricing from resource adequacy contracts.
Current wording
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.
Previous wording
The following table presents our consolidated operating and non-operating expenses and income for the six months ended June 30, 2025 and June 30, 2024.
Current wording
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.
Previous wording
General and administrative expenses — General and administrative (G&A) expenses were $151 million for the six months ended June 30, 2025 compared to $120 million for the six months ended June 30, 2024, which was an increase of $31 million. The increase was primarily due to additional compensation-related expense and other corporate expense resulting from the Aera Merger.
Current wording
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.
Previous wording
Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) for the six months ended June 30, 2025 was $259 million compared to$106 million during the six months ended June 30, 2024. The increase of $153 million was primarily the result of the addition of the Aera assets included in the six months ended June 30, 2025. See Part I, Item 1 – Financial Statements, Note 2 Aera Mergerfor information on the Aera assets.
Current wording
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 Combinationsfor information on the Aera assets.
Previous wording
Asset impairments— During the six months ended June 30, 2024, we recognized a $13 million impairment for excess and obsolete materials and supplies related to our oilfield operations. We did not recognize an asset impairment during the six months ended June 30, 2025.
Current wording
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 Acquisitionsfor additional information on the impairment.
Previous wording
Taxes other than on income — Taxes other than on income for the six months ended June 30, 2025 were $117 million, which is an increase of $40 million from $77 million for the six months ended June 30, 2024. This increase was 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.
Current wording
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 increase was 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.
Previous wording
Accretion expense— Accretion expense for the six months ended June 30, 2025 was $57 million compared to $25 million for the six months ended June 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.
Current wording
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.
Previous wording
Other operating expenses, net — Other operating expenses, net decreased $12 million to $98 million for the six months ended June 30, 2025 compared to $110 million for the six months ended June 30, 2024. For the six months ended June 30, 2025 and June 30, 2024, other operating expenses, net includes the following:
Current wording
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.
Previous wording
(a)See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingenciesfor more information on a $25 million payment we made to CalGEM during the six months ended June 30, 2025.
Current wording
(a)See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingenciesfor more information on a $25 million payment we made to CalGEM during the nine months ended September 30, 2025.
Previous wording
Interest and debt expense, net— Interest and debt expense, net was $52 million for the six months ended June 30, 2025 compared to $30 million for the six months ended June 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.
Current wording
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.
Previous wording
Income taxes – The income tax provision for the six months ended June 30, 2025 was $117 million (representing an effective tax rate of 29%), compared to a benefit of $6 million (representing an effective tax rate of 75%) for the six months ended June 30, 2024. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes for additional information on our income taxes.
Current wording
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 Taxes for additional information on our income taxes.
Previous wording
The following table includes financial results and key operating data for our oil and natural gas segment for the three months ended June 30, 2025 and March 31, 2025 and the six months ended June 30, 2025 and 2024.
Current wording
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.
Previous wording
(a)Gain on asset divestitures for the six months ended June 30, 2024 related to the sale of oil and gas assets located in Ventura.
Current wording
(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.
Previous wording
The following table sets forth our average net production of oil, NGLs and natural gas sold per day in each of the California oil and natural gas 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.
Current wording
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.
Previous wording
Total average net production sold decreased to 137 MBoe/d for the three months ended June 30, 2025 compared to 141 MBoe/d for the three months ended March 31, 2025. The decrease was primarily a result of natural production decline partially offset by development results. In addition, our production-sharing contracts (PSCs), which are described below, negatively impacted our net oil production by 1 MBoe/d in the three months ended June 30, 2025 compared to the three months ended March 31, 2025.
Current wording
Total average net production sold remained flat at 137 MBoe/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.
Previous wording
Total average net production sold increased to 139 MBoe/d for the six months ended June 30, 2025 compared to 76 MBoe/d for the six months ended June 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 1 MBoe/d in the six months ended June 30, 2025 compared to the six months ended June 30, 2024.
Current wording
Total average net production sold increased to 138 MBoe/d for the nine months ended September 30, 2025 compared to 99 MBoe/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.
Previous wording
Oil — Brent prices were lower for the three months ended June 30, 2025 compared to the three months ended March 31, 2025 as well as for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. See Business Environment and Industry Outlook above for more information on factors influencing Brent commodity prices for the periods presented.
Current wording
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 Outlook above for more information on factors influencing Brent commodity prices for the periods presented.
Previous wording
NGLs — Prices for natural gas liquids during the three months ended June 30, 2025 decreased compared to the three months ended March 31, 2025, reflecting traditional seasonality. Prices for natural gas liquids during the six months ended June 30, 2025 were consistent with the same prior year period.
Current wording
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.
Previous wording
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 CO 2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO 2 deep 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 CO 2 emissions. 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 at which time we will be ready to inject subject to receipt of final regulatory approvals early in 2026.
Current wording
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 CO 2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO 2 deep 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 CO 2 emissions. 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.
Previous wording
The following tables include results for our carbon management segment for the three months ended June 30, 2025 and March 31, 2025 and the six months ended June 30, 2025 and June 30 2024.
Current wording
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.
Previous wording
Carbon management expenses decreased for thethree months ended June 30, 2025 compared to the three months ended March 31, 2025 as a result of lower lease costs related to easements.
Current wording
Carbon management expenses decreased for thethree months ended September 30, 2025 compared to the three months ended June 30, 2025 as a result of lower legal and compensation expenses.
Previous wording
Carbon management expenses increased for thesix months ended June 30, 2025 compared to the six months ended June 30, 2024 as a result of increased expenditure related to the evaluation of CCS projects and increased lease cost for the six months ended June 30, 2025.
Current wording
Carbon management expenses increased for thenine months ended September 30, 2025 compared to the nine months ended September 30, 2024 as a result of increased expenditure related to the evaluation of CCS projects and increased lease cost.
Showing the first 40 of 53 pairs. Open the source sections for the rest.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
Nine months ended September 30, 2025 compared to September 30, 2024
Current report — wording carried from elsewhere
For the nine months ended September 30, 2025 and September 30, 2024, other operating expenses, net includes the following:
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
Six months ended June 30, 2025 compared to June 30, 2024