What changed in this filing

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Item 2. Management’s Discussion and Analysis

2025-11-05 compared with 2025-08-06 · 284 added, 223 removed, 324 unchanged (61% of the section changed)

4 unchanged sentences

Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its consolidated subsidiaries as of the date presented.

Pending Berry Merger

On September 14, 2025, we entered into a definitive agreement and plan of merger (the Berry Merger Agreement) to combine with Berry Corporation (Berry) in an all-stock transaction (Berry Merger).

Berry is an independent upstream energy company that operates in two business segments:

(i) oil and natural gas and (ii) well servicing and abandonment services.

Berry's oil and gas assets are located in California and Utah.

We expect the transaction will add high quality, oil-weighted, mostly conventional proved developed reserves and sustainable cash flows to our operations.

Pursuant to the Berry Merger Agreement, on the effective date of the merger, we will issue 0.0718 shares of our common stock for each outstanding share of Berry stock.

Upon completion of the Berry Merger, we expect our existing stockholders to own approximately 94% of the combined company upon closing.

We expect Berry's outstanding long-term debt to be repaid and the underlying credit agreement to be terminated at closing.

We expect to repay a significant portion of this indebtedness with proceeds from our 2034 Senior Notes, which closed in October 2025.

Berry's Revolving Credit Facility is also expected to be terminated at closing.

For more information on the 2034 Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 16 Subsequent Events .

Closing of the Berry Merger is subject to certain conditions, including, among others, adoption of the Berry Merger Agreement by its stockholders, expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, prior authorization by the Federal Energy Regulatory Commission under Section 203 of the Federal Power Act and other customary closing conditions.

The Berry Merger is expected to close in the first quarter of 2026.

Business Environment and Industry Outlook

1 unchanged sentence

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.

Oil and natural gas prices and differentials can fluctuate significantly due to various market-related factors, making it challenging to predict realized prices reliably.

We may respond to changing economic conditions by adjusting the amount and allocation of our capital program or by pursuing additional efficiencies and cost savings.

Prolonged volatility in oil and natural gas prices may also affect the quantities of reserves that we can economically produce over the longer term.

Refer to Results of Our Oil and Natural Gas Operations, Production, Prices and Realizations below for information on our realized prices.

During 2025, 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.

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.

During 2025, oil prices experienced volatility driven by global supply and demand factors, including a series of announcements by OPEC+ indicating its intention to return offline production to the market more quickly than previously anticipated, and by concerns over global trade following multiple tariff announcements.

The following table presents the average daily benchmark prices for oil and natural gas during the periods presented:

Three months ended Six months ended

June 30, 2025 March 31, 2025 June 30, 2025

June 30, 2024

Three months ended Nine months ended

September 30, June 30, September 30, September 30,

2025 2025 2025 2024

Brent oil ($/Bbl) $ 68.13 $ 66.76 $ 69.94 $ 81.79

3 unchanged sentences

Supply Chain and Inflation

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.

We continued to experience relatively flat pricing from our suppliers during the first nine months of 2025 compared to the prior year.

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.

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.

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 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.

We also pre-purchased inventory prior to the implementation of the tariffs and continue to purchase from vendors who source domestic content to limit the impact of foreign tariffs on our business.

Overall, we expect minimal impact from tariffs on our supply chain in 2025.

However, if the current tariff regime persists or expands, our inventory, capital and operating costs could increase over the long-term.

Marketing Arrangements

In October 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.

In October 2025, Phillips 66 closed its Wilmington refinery in Los Angeles, California.

In April 2025, Valero notified the California Energy Commission of its intent to idle, restructure, or cease refining operations at its Benicia refinery in the San Francisco Bay Area by the end of April 2026.

Although Valero has stated that it is in ongoing discussion with the California government, it recently confirmed plans to cease refining operations at Benicia and presently does not expect any changes to the previously announced timeline.

We have historically sold a portion of our crude oil to these refineries.

Following the closure of the Phillips 66 refinery, and assuming Valero's Benicia refinery ceases operations, six major petroleum refineries would remain in California, each with a refining capacity exceeding 75,000 barrels per day.

Five of these refineries currently purchase California crude oil.

If Valero's Benicia refinery ceases operations, California would have approximately 1.1 million barrels per day of refining capacity available to process California crude oil, which is approximately four times the volume of crude oil produced in the state in 2024.

Given this available refining capacity and the flexibility we have in marketing our crude oil production, we do not currently expect the cessation of operations at these refineries, should the Valero Benicia refinery cease operations, to have a material impact on our ability to market our crude oil.

While these announcements have not affected our price realizations to date, a reduction in the number of refineries operating in California has the potential to impact our future price realizations.

Regulatory Updates

Recent Legislation

Senate Bill 237 (Oil and Gas Permitting)

Senate Bill 237 (SB 237) was enacted in September 2025 and implements a number of changes to help facilitate new and continued oil and gas production in California (particularly in Kern County).

Among other provisions, SB 237 deems a specified Kern County environmental impact report sufficient for full compliance with the requirements of the California Environmental Quality Act (CEQA) for purposes of a certain County of Kern zoning ordinance related to oil and gas activities and requires no further environmental review.

These provisions of SB 237 will become effective as of January 1, 2026.

We expect Kern County and the California Geologic Energy Management Division to resume issuing new well permits in Kern County in 2026 up to the maximum allowable amount of 2,000 new drill wells per year for up to ten years.

We believe that this legislation provides greater regulatory certainty for oil and gas operations in Kern County, which accounts for a substantial portion of California’s crude oil and natural gas production.

The adoption of SB 237 is particularly important to our business as we are the largest producer of oil and gas in Kern County and the majority of our production and reserves are located there.

By facilitating the timely resumption of permitting activity, we expect that this legislation will support operational continuity and investment planning by California’s oil and gas industry.

In addition, we believe that the increased clarity around permitting standards will help to enhance long-term development opportunities in Kern County, benefiting both the broader industry and CRC’s asset base in the region.

Assembly Bill 1207 (Cap-and-Invest Extension)

Assembly Bill 1207 (AB 1207) was enacted in September 2025.

AB 1207 primarily extends California’s greenhouse-gas Cap-and-Invest program through 2045, providing long-term policy certainty for covered entities under the Program.

AB 1207 establishes emission reduction initiatives and enhances program transparency through expanded reporting requirements for the California Air Resources Board.

The legislation also establishes a Climate Mitigation Fund to support consumer rebates and investments to reduce household energy costs.

Senate Bill 614 (Carbon Dioxide Pipeline Regulation)

Senate Bill 614 (SB 614), enacted in October 2025, revises the definition of “pipeline” for purposes of the Elder California Pipeline Safety Act of 1981 to include intrastate pipelines used for the transportation of carbon dioxide (CO₂).

The law requires the Office of the State Fire Marshal to, by July 1, 2026, adopt implementing regulations regarding the safe transportation of CO₂ in pipelines, after which the current moratorium on CO₂ pipeline operations may be lifted.

The legislation mandates stringent design, routing, and disclosure standards consistent with or exceeding federal requirements under the Pipeline and Hazardous Materials Safety Administration.

Upon implementation, SB 614 is expected to enable the development of carbon-capture and storage infrastructure in California while imposing additional permitting, safety, and compliance obligations on operators of CO₂ transportation systems.

Well Permitting

During the three months ended 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.

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.

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.

During the three months ended September 30, 2025, we received well permits for 140 workovers and 89 sidetracks.

During the nine months ended September 30, 2025, we have received total well permits for 279 workovers, 194 sidetracks and 5 deepenings.

We have not received any permits for new oil and gas wells in 2025.

We believe that the enactment of SB 237 will ultimately result in CalGEM issuing new well permits beginning in 2026, and expect the rate of workover and sidetrack permit approvals to also increase throughout 2026.

We currently hold sufficient permits to exit the year with a four drilling rig capital program.

Our ability to maintain a four drilling rig program throughout 2026 will require us to obtain new permits which we expect to become available in 2026 following the enactment of SB 237.

See Liquidity and Capital Resources, Capital Program for more information.

For further information regarding well permitting, see Part I, Items 1 & 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities, Well Permitting in our 2024 Annual Report.

Kern County EIR Litigation

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.

Waste Emissions Charge

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.

14th and commonly referred to as the One Big Beautiful Bill Act, postponed implementation from 2024 to 2034.

Water Injection

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.

The Trial Court may act in the Kern County litigation matter later this year, although timing is uncertain.

The enactment of SB 237 does not result in an immediate dismissal of the pending litigation, although it will provide support for dismissal of this litigation if it is still pending when the law becomes effective in January 2026.

Developments in this litigation or in the permitting process more broadly that are adverse to Kern County could further adversely affect our business, results of operations and financial condition.

Statements of Operations Analysis

Our consolidated results of operations include the results of Aera beginning 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.

Our consolidated results of operations include the results of Aera beginning on July 1, 2024, the closing date of the Aera Merger.

For more information on the Aera Merger, see Part I, Item 1 – Financial Statements, Note 2 Business Combinations .

The Aera Merger affected the comparability of our financial results for the nine months ended September 30, 2025 to the prior comparative period.

Consolidated Results of Operations

Three months ended June 30, 2025 compared to March 31, 2025

Three months ended September 30, 2025 compared to June 30, 2025

The following table presents our consolidated operating revenues for the periods indicated:

Three months ended

June 30, 2025 March 31, 2025

September 30, 2025 June 30, 2025

(in millions)

Oil, natural gas and natural gas liquids sales

Net gain from commodity derivatives

Net (loss) gain from commodity derivatives

Revenue from marketing of purchased commodities

2 unchanged sentences

Total operating revenues $ 855 $ 978

Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $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.

The following table shows changes in oil, natural gas and natural gas liquids sales for the three months ended June 30, 2025 compared to the three months ended March 31, 2025:

Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $715 million for the three months ended September 30, 2025, which is an increase of $14 million compared to $702 million for the three months ended June 30, 2025.

The following table shows changes in oil, natural gas and natural gas liquids sales for the three months ended September 30, 2025 compared to the three months ended June 30, 2025:

Oil NGLs Natural Gas Total Operations

(in millions)

Three months ended March 31, 2025

$ 736 $ 50 $ 28 $ 814

Three months ended June 30, 2025 $ 644 $ 39 $ 19 $ 702

Changes in realized prices

(85) (11) (14) (110)

Changes in production and other

1 unchanged sentence

Changes in intersegment revenues

Three months ended June 30, 2025 $ 644 $ 39 $ 19 $ 702

Three months ended September 30, 2025 $ 653 $ 36 $ 26 $ 715

See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

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.

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.

1 unchanged sentence

Three months ended

June 30, 2025 March 31, 2025

September 30, 2025 June 30, 2025

(in millions)

Non-cash commodity derivative gain

Net proceeds (settlements) and amortized premiums

Net gain from commodity derivatives

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.

The following table presents our consolidated operating and non-operating expenses and income for the three months ended June 30, 2025 and March 31, 2025.

Non-cash commodity derivative (loss) gain

Net proceeds and premium amortization

Net (loss) gain from commodity derivatives

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.

The following table presents our consolidated operating and non-operating expenses and income for the three months ended September 30, 2025 and June 30, 2025.

Three months ended

June 30, 2025 March 31, 2025

September 30, 2025 June 30, 2025

(in millions)

Operating expenses

Energy operating costs $ 78 $ 103

Gas processing costs 5 4

Non-energy operating costs 212 209

Operating costs

General and administrative expenses 87 79

Depreciation, depletion and amortization 123 128

Asset impairment 2 —

Taxes other than on income 70 47

3 unchanged sentences

Accretion expense 28 28

Net loss (gain) on natural gas purchase derivatives

Measurement period adjustments, net

Net loss on natural gas purchase derivatives 27 3

Other operating expenses, net 29 65

Total operating expenses 756 711

Loss on asset divestitures

Operating income

1 unchanged sentence

Interest and debt expense, net

Loss on early extinguishment of debt

Loss from investment in unconsolidated subsidiaries

2 unchanged sentences

Income tax provision

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.

Operating costs — The following table presents our operating costs for the three months ended September 30, 2025 and June 30, 2025:

Three months ended

September 30, 2025 June 30, 2025

(in millions)

Energy operating costs $ 92 $ 78

Gas processing costs 6 5

Non-energy operating costs 218 212

Operating costs

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.

We do not allocate the costs to produce steam at our Elk Hills power plant which is then used in oil and natural gas operations.

Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills.

Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.

Energy operating costs — Energy operating costs for the three months ended 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 of natural gas used in our steamflood operations .

For more information on natural gas market prices, see Prices and Realizations below.

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.

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.

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.

Other operating expenses, net — Other operating expenses, net increased $32 million to $65 million for 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:

Energy operating costs — Energy operating costs for the three months ended September 30, 2025 were $92 million, which was an increase of $14 million from $78 million for the three months ended June 30, 2025.

This increase was primarily due to higher prices for electricity and natural gas used in our steamflood operations.

Taxes other than on income — Taxes other than on income for the three months ended September 30, 2025 were $70 million, which was an increase of $23 million from $47 million for the three months ended June 30, 2025.

The three months ended June 30, 2025, included a downward adjustment to our estimated annual production tax rate.

Greenhouse gas expense increased for the three months ended September 30, 2025 due to running the Elk Hills power plant at a higher operational capacity and market prices for purchased allowances were higher than prevailing market prices during the three months ended June 30, 2025.

Net loss on natural gas purchase derivatives — Net loss from derivatives related to our purchase of natural gas was $27 million for the three months ended September 30, 2025 compared to a net loss of $3 million for the three months ended June 30, 2025.

The change primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held, as well as the relationship between contract prices and the associated forward curves at the end of each measurement period.

Gains and losses from our commodity derivative contracts are shown in the table below:

Three months ended

June 30, 2025 March 31, 2025

September 30, 2025 June 30, 2025

(in millions)

Carbon management business expense

Aera transaction and integration costs

Front-end engineering design studies

Non-cash loss (gain) on natural gas purchase derivatives

Net loss on natural gas purchase derivatives

Other operating expenses, net — Other operating expenses, net decreased $36 million to $29 million for the three months ended September 30, 2025 compared to $65 million for the three months ended June 30, 2025.

For the three months ended September 30, 2025 and June 30, 2025, other operating expenses, net includes the following:

Three months ended

September 30, 2025 June 30, 2025

(in millions)

Carbon management expenses

Transaction and integration costs

Signal Hill decommissioning expense

Litigation and settlement related expenses (a)

1 unchanged sentence

(a) See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for more information on a $25 million payment we made to CalGEM during the three months ended June 30, 2025.

Income taxes – The income tax provision for the three months ended 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.

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 .

Six months ended June 30, 2025 compared to June 30, 2024

Nine months ended September 30, 2025 compared to September 30, 2024

The following table presents our consolidated operating revenues for the periods indicated:

Six months ended

June 30, 2025 June 30, 2024

Nine months ended

September 30, 2025 September 30, 2024

(in millions)

1 unchanged sentence

$ 2,231 $ 1,711

Net gain (loss) from commodity derivatives

Net gain from commodity derivatives 140 290

Revenue from marketing of purchased commodities

2 unchanged sentences

Total operating revenues $ 2,745 $ 2,321

Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $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.

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.

Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $2,231 million for the nine months ended September 30, 2025, which is an increase of $520 million compared to $1,711 million for the nine months ended September 30, 2024.

The following table shows changes in oil, natural gas and natural gas liquids sales for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024.

Oil NGLs Natural Gas Total Operations

(in millions)

Six months ended June 30, 2024 $ 701 $ 94 $ 46 $ 841

Nine months ended September 30, 2024 $ 1,505 $ 138 $ 68 $ 1,711

Changes in realized prices

4 unchanged sentences

— — (18) (18)

Six months ended June 30, 2025 $ 1,380 $ 89 $ 47 $ 1,516

Nine months ended September 30, 2025 $ 2,033 $ 125 $ 73 $ 2,231

See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

(a) The increase in production primarily relates to the addition of the Aera fields on July 1, 2024.

See Part I, Item 1 – Financial Statements, Note 2 Aera Merger for additional information.

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.

See Part I, Item 1 – Financial Statements, Note 2 Business Combinations for additional information.

Net gain from commodity derivatives – We report gains and losses on our derivative contracts related to sales of our produced oil and marketing activities in operating revenue.

Net gain from commodity derivatives was $140 million for the nine months ended September 30, 2025 compared to a net gain of $290 million for the nine months ended September 30, 2024.

The change primarily resulted from payments to settle commodity derivative contracts and the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period.

Gains and losses from our commodity derivative contracts are shown in the table below:

Six months ended

June 30, 2025 June 30, 2024

Nine months ended

September 30, 2025 September 30, 2024

(in millions)

Non-cash commodity derivative gain (loss)

Net settlements and amortized premiums

Net gain (loss) from commodity derivatives $ 163 $ (66)

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.

Non-cash commodity derivative gain

Net proceeds (settlements) and premium amortization

Net gain from commodity derivatives

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.

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.

Six months ended

June 30, 2025 June 30, 2024

Additionally, we experienced lower revenues during the nine months ended September 30, 2024 as a result of downtime at our Elk Hills power plant.

The following table presents our consolidated operating and non-operating expenses and income for the nine months ended September 30, 2025 and September 30, 2024.

Nine months ended

September 30, 2025 September 30, 2024

(in millions)

Operating expenses

Energy operating costs $ 181 $ 94

Gas processing costs 9 7

Non-energy operating costs 421 231

Operating costs

General and administrative expenses 238 226

6 unchanged sentences

Accretion expense 85 56

Net (gain) loss on natural gas purchase derivatives

Net loss on natural gas purchase derivatives 24 11

Measurement period adjustments, net

1 unchanged sentence

Total operating expenses 2,193 1,776

Gain on asset divestitures — 7

(Loss) gain on asset divestitures

Operating income

3 unchanged sentences

Loss from investment in unconsolidated subsidiaries

Other non-operating income, net

Other non-operating income (expenses), net

Income before income taxes

Income tax (provision) benefit

Net income (loss)

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.

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.

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 increas e of $31 million .

The increase was primarily due to additional compensation-related expense and other corporate expense resulting from the Aera Merger.

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 durin g 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 Merger for information on the Aera assets.

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.

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.

Income tax provision

Operating costs — The following table presents our operating costs for the nine months ended September 30, 2025 and September 30, 2024.

Nine months ended

September 30, 2025 September 30, 2024

(in millions)

Energy operating costs $ 273 $ 186

Gas processing costs 15 12

Non-energy operating costs 639 445

Operating costs

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.

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.

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 increas e of $12 million.

The increase was primarily due to additional compensation-related expense and other corporate expenses resulting from the Aera Merger.

Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) for the nine months ended September 30, 2025 was $382 million compared to $246 million durin g the nine months ended September 30, 2024.

The increase of $136 million was primarily the result of the addition of the Aera assets included in the nine months ended September 30, 2025.

See Part I, Item 1 – Financial Statements, Note 2 Business Combinations for information on the Aera assets.

Asset impairments — During the nine months ended September 30, 2024, we recognized a $13 million impairment for excess and obsolete materials and supplies related to our oilfield operations.

We recognized a $2 million asset impairment during the nine months ended September 30, 2025 related to a fair value adjustment for properties held for sale.

See Part I, Item 1 – Financial Statements, Note 8 Divestitures and Acquisitions for additional information on the impairment.

Taxes other than on income — Taxes other than on income for the nine months ended September 30, 2025 were $187 million, which is an increase of $25 million from $162 million for the nine months ended September 30, 2024.

This 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.

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.

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.

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:

Six months ended

June 30, 2025 June 30, 2024

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.

Gains and losses from our commodity derivative contracts are shown in the table below:

Nine months ended

September 30, 2025 September 30, 2024

(in millions)

Non-cash loss (gain) on natural gas purchase derivatives

Net loss on natural gas purchase derivatives $ 24 $ 11

Other operating expenses, net — Other operating expenses, net decreased $61 million to $127 million for the nine months ended September 30, 2025 compared to $188 million for the nine months ended September 30, 2024.

For the nine months ended September 30, 2025 and September 30, 2024, other operating expenses, net includes the following:

Nine months ended

September 30, 2025 September 30, 2024

(in millions)

Carbon management business expense

Aera transaction and integration costs

Transaction and integration costs

Energy costs due to downtime at Elk Hills power plant

Litigation and settlement related expenses (a)

Offshore platforms maintenance and abandonment

Information technology infrastructure

Total operating expenses, net

(a) See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for more information on a $25 million payment we made to CalGEM during the six months ended June 30, 2025.

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.

(a) See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for more information on a $25 million payment we made to CalGEM during the nine months ended September 30, 2025.

Interest and debt expense, net — Interest and debt expense, net was $77 million for the nine months ended September 30, 2025 compared to $59 million for the nine months ended September 30, 2024.

The increase was predominantly due to higher interest expense resulting from the issuance of our 2029 Senior Notes.

In June 2024, we issued $600 million in aggregate principal amount of 2029 Senior Notes and in August 2024, we completed a follow-on offering of $300 million in aggregate principal amount of 2029 Senior Notes.

Income taxes – The income tax provision for the 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.

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.

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Results of Our Oil and Natural Gas Operations

The following table includes financial results and key operating data for our oil and natural gas segment for the three months ended June 30, 2025 and March 31, 2025 and the six months ended June 30, 2025 and 2024.

Three months ended Six months ended

June 30, 2025 March 31, 2025 June 30, 2025 June 30, 2024

The following table includes financial results and key operating data for our oil and natural gas segment for the three months ended September 30, 2025 and June 30, 2025 and the nine months ended September 30, 2025 and 2024.

Three months ended Nine months ended

September 30, June 30, September 30, September 30,

2025 2025 2025 2024

(in millions, except as otherwise stated)

Production and segment financial data

Production and oil and gas segment financial data

Net production sold (MBoe/d)

137 137 138 99

Segment total operating revenues

Total operating revenues

$ 728 $ 714 $ 2,272 $ 1,734

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Items affecting comparability:

Gain on asset divestitures (a)

Net (loss) gain on asset divestitures (a)

$ (1) $ — $ (1) $ 6

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$ 25.75 $ 24.75 $ 25.68 $ 24.76

Segment general and administrative expenses (b)

General and administrative expenses (b)

$ 0.72 $ 0.72 $ 0.80 $ 2.65

Segment depreciation, depletion and amortization (c)

Depreciation, depletion and amortization (c)

$ 9.39 $ 9.69 $ 9.68 $ 8.55

Segment taxes other than on income

Taxes other than on income

$ 4.54 $ 3.28 $ 4.16 $ 5.05

(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.

(b) Excludes unallocated general and administrative expenses.

(a) Net loss on asset divestitures for the three and nine months ended September 30, 2025 related to the sale of oil and gas assets located in Ventura.

Net gain on asset divestitures for the nine months ended September 30, 2024 related to the sale of our Fort Apache parcel in Huntington Beach.

(b) Includes general and administrative expenses allocated to our oil and natural gas segment.

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Net Production Sold

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 following table presents our net production sold per day in each of the California basins in which we operate for the periods presented.

The amounts in the production table below include volumes produced from operated and non-operated fields for each of the periods presented.

Three months ended Six months ended

June 30, 2025 March 31, 2025 June 30, 2025 June 30, 2024

Three months ended Nine months ended

September 30, June 30, September 30, September 30,

2025 2025 2025 2024

San Joaquin Basin 81 83 83 50

11 unchanged sentences

137 137 138 99

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.

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.

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.

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 1 MBoe/d in the six months ended June 30, 2025 compared to the six months ended June 30, 2024.

Our PSCs, which are described below, positively impacted our net oil production by approximately 2 MBoe/d in the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024.

Production-Sharing Contracts

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Three months ended

June 30, 2025 March 31, 2025

September 30, 2025 June 30, 2025

Price Realization Price Realization

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Realized price ($/Mcf) $ 3.47 113% $ 2.79 81%

Six months ended

June 30, 2025 June 30, 2024

Nine months ended

September 30, 2025 September 30, 2024

Price Realization Price Realization

13 unchanged sentences

Realized price ($/Mcf) $ 3.46 102% $ 2.76 131%

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.

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.

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.

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.

NGLs — Prices for natural gas liquids during the three months ended September 30, 2025 decreased compared to the three months ended June 30, 2025, reflecting typical seasonal patterns.

Prices for natural gas liquids during the nine months ended September 30, 2025 were lower than in the same prior year period, consistent with broader declines in oil commodity prices.

Natural Gas — Natural gas index prices decreased for the three months ended September 30, 2025 compared to the three months ended June 30, 2025 driven by substantial natural gas production relative to modest demand for electricity generation.

Realized natural gas prices in California were higher in the three months ended September 30, 2025 compared to the three months ended June 30, 2025 reflecting pipeline system maintenance and constraints impacting natural gas deliveries into California.

Natural gas prices increased for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 driven by higher demand in 2025 and the effects of elevated inventories in the prior year.

Results of Our Carbon Management Segment

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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.

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.

Three months ended

Six months ended

June 30, 2025 March 31, 2025 June 30, 2025 June 30, 2024

We expect construction of our first carbon capture project at our cryogenic gas processing facility to be completed at or around year end.

We expect first injection in 2026, subject to receipt of final regulatory approvals.

The following tables include results for our carbon management segment for the three months ended September 30, 2025 and June 30, 2025 and the nine months ended September 30, 2025 and September 30 2024.

Three months ended Nine months ended

September 30, June 30, September 30, September 30,

2025 2025 2025 2024

(in millions) (in millions)

$ (21) $ (20) $ (66) $ (63)

Three months ended

Six months ended

June 30, 2025 March 31, 2025 June 30, 2025 June 30, 2024

Three months ended Nine months ended

September 30, June 30, September 30, September 30,

2025 2025 2025 2024

(in millions) (in millions)

5 unchanged sentences

$ 2 $ 1 $ 4 $ 10

Carbon management expenses decreased for the three months ended June 30, 2025 compared to the t hree months ended March 31, 2025 as a result of lower lease costs related to easements.

Carbon management expenses increased for the six 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.

Carbon management expenses decreased for the three months ended September 30, 2025 compared to the t hree months ended June 30, 2025 as a result of lower legal and compensation expenses.

Carbon management expenses increased for the nine months ended September 30, 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.

Liquidity and Capital Resources

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We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining.

Our primary uses of operating cash flow for the three and six months ended June 30, 2025 were for repurchases of our common stock, payment of dividends, and capital investments.

Our primary uses of operating cash flow for the three and nine months ended September 30, 2025 were for repurchases of our common stock, payment of dividends, and capital investments.

The following table summarizes our liquidity:

June 30, 2025

September 30, 2025

(in millions)

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At current commodity prices and based upon our planned 2025 capital program described below, we expect to generate operating cash flow to return cash to shareholders through dividends and repurchases of our common stock.

In line with this strategy, our Board of Directors has extended the term of our Share Repurchase Program from December 31, 2025 to June 30, 2026.

We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or share repurchases to the extent permitted under our Revolving Credit Facility and the indentures for our 7.125% senior notes due 2026 (2026 Senior Notes) and our 8.25% senior notes due 2029 (2029 Senior Notes), (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet.

We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or share repurchases to the extent permitted under our Revolving Credit Facility, our 8.25% senior notes due 2029 (2029 Senior Notes), and our 7.00% senior notes due 2034 (2034 Senior Notes) (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet.

We continue to monitor the current macroeconomic environment and will adjust our planned uses of cash as necessary.

We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.

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.

On July 4, 2025, An Act to Provide for Reconciliation Pursuant to Title II of H.

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.

Revolving Credit Facility

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt in our 2024 Annual Report for information on the Revolving Credit Facility and related amendments.

See Part I, Item 1 – Financial Statements, Note 16 Subsequent Events for information on a recent amendment to our Revolving Credit Facility.

2034 Senior Notes

See Part I, Item 1 – Financial Statements, Note 16 Subsequent Events for information on our 2034 Senior Notes.

2026 Senior Notes Redemption

See Part I, Item 1 – Financial Statements, Note 4 Debt for information on a partial redemption of our 2026 Senior Notes.

See Part I, Item 1 – Financial Statements, Note 4 Debt and Note 16 Subsequent Events for information on the redemption of our 2026 Senior Notes.

Share Repurchase Program

See Part I, Item 1 – Financial Statements, Note 10 Stockholders' Equity and Part II, Item 2 – Other Information, Unregistered Sales of Equity Securities and Use of Proceeds for more information on our Share Repurchase Program including a repurchase of shares during the second quarter of 2025 from IKAV.

See Part I, Item 1 – Financial Statements, Note 10 Stockholders' Equity for more information on our dividends.

See Part I, Item 1 – Financial Statements, Note 16 Subsequent Events for information on a dividend declared in August 2025.

See Part I, Item 1 – Financial Statements, Note 16 Subsequent Events for information on an increased dividend declared in November 2025.

Capital Program

Our capital program is dynamic in response to commodity price volatility and permit availability while focusing on oil production and maximizing our free cash flow.

Our capital investment for the six months ended June 30, 2025 was $111 million.

Our capital investment for the nine months ended September 30, 2025 was $202 million.

We expect our full year 2025 capital program to range between $280 million and $330 million.

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The above amounts related to carbon management projects do not include amounts funded by Brookfield through the Carbon TerraVault JV, such as drilling injection and monitoring wells at our 26R reservoir.

With respect to oil and natural gas development, we added a second drilling rig in June 2025 and currently expect to run our two rig program through the remainder of the year using existing permits in hand.

With respect to oil and natural gas development, we ran an average of two rigs during the three months ended September 30, 2025 and expect to exit the year with four rigs.

Refer to Regulatory Updates above for more information on permitting.

Refer to Part I, Item 1 – Financial Statements, Note 9 Segment Information for information on capital investment by segment.

We plan to average four rigs during 2026, which activity is underpinned by the strength of hedges currently in place.

We expect to operate four rigs using existing permits and new permits which we expect to become available in 2026 following the recent enactment of SB 237.

We retain the flexibility to adjust our 2026 capital plan to reflect changes in commodity prices and other market factors.

This program does not include the impact of the Berry Merger.

Significant changes in oil and natural gas prices may have a material impact on our liquidity.

3 unchanged sentences

Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges.

We did not have any commodity derivatives designated as accounting hedges as of and during the six months ended June 30, 2025.

See Part I, Item 1 – Financial Statements, Note 6 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of June 30, 2025 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt in our 2024 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

We did not have any commodity derivatives designated as accounting hedges as of and during the nine months ended September 30, 2025.

See Part I, Item 1 – Financial Statements, Note 6 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of September 30, 2025 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt in our 2024 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

Cash Flow Analysis

Cash flows from operating activities — For the six months ended June 30, 2025, our operating cash flow increased by $167 million to $351 million from $184 million in the same period in 2024.

Cash flows from operating activities — For the nine months ended September 30, 2025, our operating cash flow increased by $226 million to $630 million from $404 million in the same period in 2024.

This increase in operating cash flow was primarily driven by the Aera Merger on July 1, 2024.

With the addition of Aera's assets, oil production during the six months ended June 30, 2025 as compared to the same period in 2024 increased 63 MBbl/d from 47 MBbl/d to 110 MBbl/d.

Oil production during the nine months ended September 30, 2025 as compared to the same period in 2024 increased 40 MBbl/d from 69 MBbl/d to 109 MBbl/d as a result of the Aera Merger.

Higher revenue from this increase in production was partially offset by lower average realized oil prices (after derivative settlements).

Average realized prices for oil decreased by $9.81 per barrel to $69.39 in the six months ended June 30, 2025 from $79.20 in the same prior year period.

Further, as a result of the Aera Merger, we experienced higher operating costs, production taxes and greenhouse gas taxes during the six months ended June 30, 2025 as compared to the same prior year period in addition to one-time transaction and integration costs were incurred in 2025.

During the six months ended June 30, 2024, scheduled plant downtime at the Elk Hills power plant negatively impacted our production and we purchased electricity at higher prices.

Average realized prices for oil decreased by $8.49 per barrel to $68.61 in the nine months ended September 30, 2025 from $77.10 in the same prior year period.

Further, as a result of the Aera Merger, we experienced higher operating costs, employee costs, well abandonment costs, production taxes and greenhouse gas taxes during the nine months ended September 30, 2025 as compared to the same prior year period.

During the nine months ended September 30, 2024, downtime at the Elk Hills power plant negatively impacted our production and we purchased electricity at higher prices.

Cash flows used in investing activities — The following table provides a comparative summary of net cash used in investing activities:

Six months ended

Nine months ended

September 30,

(in millions)

2 unchanged sentences

Proceeds from asset divestitures

Purchase of a business, net of cash acquired

Acquisitions — (6)

2 unchanged sentences

Cash flows used in financing activities — The following table provides a comparative summary of net cash used in financing activities:

Six months ended

Nine months ended

September 30,

(in millions)

Proceeds from Revolving Credit Facility

Repayments of Revolving Credit Facility (150) (30)

Proceeds from 2029 Senior Notes, net

6 unchanged sentences

Debt amendment costs

Debt issuance costs

Stock warrants exercised

Shares cancelled for taxes (12) (42)

Net cash provided by (used in) financing activities

Net cash (used in) provided by financing activities

$ (589) $ 351

1 unchanged sentence

Commissions paid on share repurchases were not significant in all periods presented.

For the six months ended June 30, 2025, our cash flow used in financing activities was $521 million compared to cash flow provided by financing activities of $433 million in the same period in 2024.

This decrease in cash flow from financing activities was primarily driven by the $590 million of proceeds from 2029 Senior Notes issued in the six months ended June 30, 2024.

Additionally, the decrease is caused by the $123 million cash outflow used to redeem a portion of the 2026 Senior Notes in February 2025 and the $318 million cash outflow used to repurchase stock in the six months ended June 30, 2025.

For the nine months ended September 30, 2025, our cash flow used in financing activities was $589 million compared to cash flow provided by financing activities of $351 million in the same period in 2024.

This decrease in cash flow from financing activities was primarily driven by the $888 million of proceeds from 2029 Senior Notes issued in the nine months ended September 30, 2024.

Additionally, the decrease is caused by the $352 million cash outflow used to repurchase stock in the nine months ended September 30, 2025 compared to $135 million in the nine months ended September 30, 2024.

Divestitures and Assets Held for Sale

See Part I, Item 1 – Financial Statements, Note 8 Divestitures and Assets Held for Sale for information on our divestitures and acquisitions during the three months ended June 30, 2025 and 2024.

See Part I, Item 1 – Financial Statements, Note 8 Divestitures and Assets Held for Sale for information on our divestitures and acquisitions during the three months ended September 30, 2025 and 2024.

Lawsuits, Claims, Commitments and Contingencies

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(2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of our products;

• the expected timing and resumption of the issuance of well permits following the enactment of SB 237;

• the efforts of activists to delay prevent oil and gas activities or the development of our carbon management segment through a variety of tactics, including litigation;

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• 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 realize the benefits contemplated by our energy transition

strategies and initiatives, including CCS projects and other renewable energy efforts;

• our ability to successfully identify, develop and finance carbon capture and storage projects, power projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and our ability to convert our CDMAs to definitive agreements and enter into other offtake agreements;

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• pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19 pandemic;

• transaction costs;

• unknown liabilities

• the risk that any announcements relating to the Berry Merger could have adverse effects on the market price of our common stock;

• the ability to successfully integrate Berry;

• the ability to achieve projected synergies from the Berry Merger or it may take longer than expected to achieve synergies;

• risks related to financial community and rating agency perceptions of us and our business, operations, financial condition and the industry in which we operate;

• the occurrence of any event, change or other circumstances that could give rise to the termination of the Berry Merger;

• the risk that stockholders of Berry may not approve the Berry Merger;

• the risk that the any of the other closing conditions to the Berry Merger may not be satisfied in a timely manner, including the risk that all necessary regulatory approvals may not be obtained or may be obtained subject to conditions that are not anticipated;

• risks related to disruption of management time from ongoing business operations due to the Berry transaction;

• effects of the announcement, pendency or completion of the transaction on our ability to retain customers and retain and hire key personnel and maintain relationships with our suppliers and customers;

• other factors discussed in Part I, Item 1A – Risk Factors of our 2024 Annual Report.

3 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis