California Resources Corp
For the period ended Mar 31, 2026. Filed May 6, 2026.
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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.
Mar 31, 2026 · Filed May 6, 2026
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 2025-09-30; filed 2025-11-05.
0001609253-25-000090
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-05-06.
0001609253-26-000106
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 193 previous paragraphs and 147 current paragraphs.
82 unchanged; 33 reworded; 32 added; 69 removed; 9 previous and 0 current paragraphs rearranged.
Tables are not compared: 24 previous and 15 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 (32)
Current report
Global oil prices increased significantly towards the end of the three months ended March 31, 2026 and continuing to date through the second quarter due to military conflicts and geopolitical tensions. In March 2026, oil prices escalated sharply as Middle East crude and product flows from the region were interrupted due to damage to regional energy infrastructure and the effective closure of the Strait of Hormuz. Additionally, oil prices were affected to a lesser extent by Ukrainian military strikes that significantly impacted Russian export capabilities. We expect oil prices to remain volatile as these geopolitical circumstances continue to evolve. Refer to Results of Our Oil and Natural Gas Operations, Production, Prices and Realizations below for information on our realized prices.
Current report
We continued to experience relatively flat pricing from our suppliers during the first three months of 2026 compared to the prior year. U.S. tariff policy regarding both country of origin and material type remains highly uncertain and subject to future changes. During 2025, the United States significantly expanded tariff rates on imported goods, including increasing Section 232 tariffs on steel and aluminum to 50% and adding copper at the same rate. In February 2026, the Supreme Court ruled that the President's use of emergency powers under the International Emergency Economic Powers Act to impose country-specific "reciprocal" tariffs was unconstitutional; however, Section 232 metals tariffs were not affected by this ruling. In April 2026, the Federal government further restructured the Section 232 metals tariffs establishing a tiered rate structure based on metal content and applying tariffs to the full customs value of imported articles rather than only the embedded metal content.
Current report
These expanded and restructured tariff rates are expected to increase our cost of oilfield goods and extend delivery lead times over the longer term. The shift to full-value assessment for derivative articles, in particular, may increase duty burdens on certain imported components and assemblies beyond prior levels. Overall, we expect a slight impact from tariffs on our supply chain in 2026. We believe we can mitigate a portion of these cost increases through bulk purchases, domestic sourcing, and ongoing review of product classifications and supplier origin. However, the evolving nature of tariff policy—including the potential for future modifications, legal challenges, and new product inclusions — creates continued uncertainty that may limit our ability to fully offset these impacts.
Current report
High fuel costs are adversely impacting transportation and equipment prices, and high oil prices are impacting oil-based products such as chemicals and lubricants. At current oil prices, we expect these costs to increase by $6 million to $8 million for the remainder of 2026.
Current report
In early 2026 Valero ceased purchasing crude oil for its Benicia refinery and it is reported that the refinery ceased operations in April 2026. While we have historically sold a portion of our crude oil to this refinery, we have not experienced difficulty in selling our production to the remaining refineries in California or any negative impact on pricing or realizations as a result of this closure.
Current report
In March 2026, the United States Secretary of Energy issued an order under the authority of the Defense Production Act of 1950 directing Sable Offshore Corp. (Sable) to restart oil and gas production at the San Ynez Unit, located in Federal offshore waters, and to facilitate the movement of offshore crude oil into California via the Las Flores pipeline. The State of California and other non-governmental organizations have filed suit against the United States Secretary of Energy and Sable, the owner of the San Ynez Unit, to block transportation of this crude oil into California. However, Sable has indicated that it is currently producing crude oil and has the potential to increase production to approximately 60,000 barrels per day. We expect that this additional production could strain existing pipeline transportation capacity required to reach refiners, which could require us to find alternative routes to market that may be limited or more costly. In addition, we expect that this production will have the potential to compete with our crude oil production in the California refining market.
Current report
During the three months ended March 31, 2026, we received permits for 66 new oil and gas wells, 21 workovers and 2 sidetracks. We currently hold sufficient permits to support a seven rig program, which includes 6 rigs in California and 1 rig in Utah, in the second half of 2026.
Current report
Water Injection
Current report
Our operations in the Wilmington Oil Field use injection wells to reinject produced water under approved 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. We expect that the next phase of reduction will remain on hold until the fall of 2026 while we evaluate the impact of the previously implemented reductions together with CalGEM. We currently estimate a negligible impact on production and reserves under the existing work plan. However, material changes to the existing plan could require revisions to these estimates.
Current report
CA Cap-and-Invest (AB 1207 and SB 840)
Current report
In January 2026, the California Air Resources Board released proposed amendments to update its existing Cap-and-Invest program. The rulemaking process is ongoing, and the final terms and requirements of any proposed amendments have not yet been determined. We are actively monitoring these developments and potential impacts to our business.
Current report
Revenue from marketing of purchased commodities— Revenue from marketing of purchased commodities was $41 million for the three months ended March 31, 2026 compared to $60 million for the three months ended December 31, 2025. The decrease was related to lower natural gas prices in California resulting from high storage levels.
Current report
Energy operating costs — Energy operating costs for the three months ended March 31, 2026 were $110 million, which was an increase of $9 million from $101 million for the three months ended December 31, 2025 primarily due to the addition of the effect of the Berry properties as part of the Berry Merger. Excluding the Berry properties, energy operating costs decreased as a result of lower natural gas prices in the three months ended March 31, 2026 compared to the three months ended December 31, 2025.
Current report
Non-energy operating costs — Non-energy operating costs for the three months ended March 31, 2026 were $250 million, which was an increase of $30 million from $220 million for the three months ended December 31, 2025 primarily due to the addition of the Berry properties following the Berry Merger. Excluding the Berry properties, non-energy operating costs decreased for the three months ended March 31, 2026 compared to the three months ended December 31, 2025 primarily due to lower compensation-related costs and less workover and surface maintenance activity.
Current report
General and administrative expenses — General and administrative (G&A) expenses were $106 million for the three months ended March 31, 2026 compared to $95 million for the three months ended December 31, 2025. The increase primarily resulted from the Berry Merger including $12 million from higher compensation-related costs related to the addition of the Berry workforce and $3 million of incremental insurance cost. Additionally, cash-settled stock-based compensation expense increased by $7 million due to higher value on our incentive awards resulting from an increase in our stock price at March 31, 2026 compared to December 31, 2025. We also had higher legal costs in the three months ended March 31, 2026 compared to the three months ended December 31, 2025. Offsetting these increases, compensation-related expenses decreased $10 million in the three months ended March 31, 2026 compared to the three months ended December 31, 2025 due to the reduction of annual incentive compensation accruals.
Current report
Changes in our stock price introduce volatility in our results of operations because we pay cash-settled incentive awards based on our stock price on the vesting date and accounting rules require that we adjust our obligation for unvested awards to the amount that would be paid using our stock price at the end of each reporting period. Consequently, any future increases in our stock price will result in additional cash-settled stock-based compensation expense. Similarly, any future decrease in our stock price will result in lower compensation expense. Equity-settled stock-based compensation awards are not similarly adjusted for changes in our stock price. General and administrative expenses for equity-settled stock-based compensation, was approximately $7 million for the three months ended March 31, 2026 and $6 million for the three months ended December 31, 2025.
Current report
Asset impairment— We did not record an asset impairment in the three months ended March 31, 2026. We recognized an asset impairment during the three months ended December 31, 2025 of $57 million related to the write-down of our proved natural gas properties in the Sacramento basin. For more information, refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Property, Plant and Equipmentin our 2025 Annual Report for more information.
Current report
Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $23 million for the three months ended March 31, 2026 compared to $47 million for the three months ended December 31, 2025. The decrease was primarily a result of lower natural gas prices and volumes purchased in the three months ended March 31, 2026.
Current report
(a)Asset impairment for the three months ended December 31, 2025 includes the write-down of our proved properties in the Sacramento basin.
Current report
Oil — Brent crude oil prices for the three months ended March 31, 2026 were volatile as market focus during the period shifted from a developing oversupply situation to shortages driven by the military conflict in the Middle East and escalating crude infrastructure damage in Russia. For the three months ended March 31, 2026, Brent crude oil prices averaged $77.90 per barrel which was higher than $63.08 for the three months ended December 31, 2025.
Current report
NGLs — Realizations on natural gas liquids during the three months ended March 31, 2026 decreased compared to the three months ended December 31, 2025 as propane inventories built despite seasonal demand. California NGLs maintained a material premium to the broader North American NGL market.
Current report
Natural Gas — North American natural gas prices for the three months ended March 31, 2026 were generally higher compared to the three months ended December 31, 2025 as the Eastern part of the country experienced unseasonably cold weather. California natural gas prices for the three months ended March 31, 2026 were lower than the three months ended December 31, 2025 as warmer-than-normal temperatures and an abundance of storage impacted prices.
Current report
On April 14, 2026, the borrowing base under our Revolving Credit Facility was reaffirmed at $1.5 billion and we entered into an amendment to the Revolving Credit Facility. For more information, see Part I, Item 1 – Financial Statements, Note 15 Subsequent Eventsfor more information.
Current report
In March 2026, we redeemed $350 million in face value of 2029 Senior Notes from the proceeds of an offering of additional 2034 Senior Notes. See Part I, Item 1 – Financial Statements, Note 4 Debtfor more information.
Current report
2034 Senior Notes
Current report
In March 2026, we completed an offering of $350 million of additional 2034 Senior Notes. See Part I, Item 1 – Financial Statements, Note 4 Debtfor more information.
Current report
With respect to oil and natural gas development, we expect to increase to a seven rig program in the second half of 2026, which includes 6 rigs in California and 1 rig in Utah. We currently hold sufficient permits to support a seven rig program in the second half of 2026.
Current report
The amounts in the table below reflect components of our capital investment for the periods indicated, excluding changes in capital investment accruals:
Current report
For the three months ended March 31, 2026, our cash flow used in financing activities was $55 million compared to $265 million in the same period in 2025. In the three months ended March 31, 2026, we completed an add-on to our 2034 Senior Notes and redeemed $350 million in face value of our 2029 Senior Notes. In the three months ended March 31, 2025, we repurchased $101 million of our common stock and redeemed $123 million of our 2026 Senior Notes.
Current report
•refinery closures and reductions in pipeline transportation capacity;
Current report
•our ability to grow and develop our carbon management segment and achieve projected injection and storage rates;
Current report
•unknown liabilities; and
Removed paragraphs (69)
Previous report
Pending Berry Merger
Previous 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.
Previous 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.
Previous 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.
Previous 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.
Previous 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.
Previous report
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 report
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 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.
Previous 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.
Previous report
Recent Legislation
Previous report
Senate Bill 237 (Oil and Gas Permitting)
Previous 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.
Previous 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.
Previous report
Assembly Bill 1207 (Cap-and-Invest Extension)
Previous 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.
Previous report
Senate Bill 614 (Carbon Dioxide Pipeline Regulation)
Previous 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.
Previous report
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 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.
Previous 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.
Previous report
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 report
Kern County EIR Litigation
Previous 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.
Previous report
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 report
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 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:
Previous report
(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 three months ended June 30, 2025.
Previous report
Nine months ended September 30, 2025 compared to September 30, 2024
Previous report
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 report
(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 report
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 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.
Previous 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.
Previous report
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 report
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 report
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 report
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 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:
Previous report
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.
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Reworded paragraphs (33)
Previous wording
We are an independent energy and carbon management company committed to energy transition. We are committed to environmental stewardship while safely providing local, responsibly sourced energy. We are also focused on maximizing the value of our land, mineral ownership, and energy expertise for decarbonization by developing carbon capture and storage (CCS) and other emissions-reducing projects.
Current wording
We are an independent energy and carbon management company advancing the energy transition. We are committed to environmental stewardship while safely providing local, responsibly sourced energy. We are also focused on maximizing the value of our land, mineral ownership, and energy expertise for decarbonization by developing carbon capture and storage (CCS) and other emissions-reducing projects.
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 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.
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 cost reductions. Significant changes in oil and natural gas prices may also affect the quantities of reserves that we can economically produce over the longer term.
Previous 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.
Current wording
Our consolidated results of operations include the results of Berry beginning on December 18, 2025, the closing date of the Berry Merger. For more information on the Berry Merger, see Part I, Item 1 – Financial Statements, Note 2 Business Combination. The Berry Merger affected the comparability of our financial results for the three months ended March 31, 2026 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 $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.
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 $905 million for the three months ended March 31, 2026, which was an increase of $226 million compared to $679 million for the three months ended December 31, 2025. Oil, natural gas and natural gas liquids sales included $131 million and $18 million for the three months ended March 31, 2026 and December 31, 2025, respectively, related to sales of additional production from the Berry properties following the completion of the Berry Merger on December 18, 2025.
Previous 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:
Current wording
Net (loss) gain from commodity sales 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 sales derivatives was $848 million for the three months ended March 31, 2026 compared to a net gain of $126 million for the three months ended December 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. Oil prices significantly increased as of March 31, 2026 compared to December 31, 2025. For instance, the Brent forward curve for the twelve months following March 31, 2026 increased by approximately 40% to $83.66 compared to $60.30 at December 31, 2025. As of March 31, 2026, we have hedges on approximately 65% of our expected oil production for the remainder of 2026 at a weighted average floor price of $64.99. Gains and losses from our commodity derivative contracts are shown in the table below:
Previous 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.
Current wording
Electricity revenue — Electricity revenue decreased by $41 million to$11 million for the three months ended March 31, 2026 compared to $52 million for the three months ended December 31, 2025. This decrease was primarily a result of reduced resource adequacy revenues as well as less electricity generated in response to market conditions during the three months ended March 31, 2026 compared to the three months ended December 31, 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 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.
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 generate electricity used in our operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.
Previous 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.
Current wording
Taxes other than on income — Taxes other than on income for the three months ended March 31, 2026 were $67 million, which was an increase of $12 million from $55 million for the three months ended December 31, 2025. The increase was primarily due to an increase in ad valorem and production taxes resulting from the Berry Merger.
Previous 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:
Current wording
Other operating expenses, net — Other operating expenses, net decreased $28 million to $54 millionfor the three months ended March 31, 2026 compared to $82 million for the three months ended December 31, 2025. For the three months ended March 31, 2026 and December 31, 2025, other operating expenses, net includes the following:
Previous 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.
Current wording
Income taxes – The income tax provision for the three months ended March 31, 2026 was a benefit of $49 million (representing an effective tax benefit of 6%), compared to a provision of $11 million (representing an effective tax rate of 48%) for the three months ended December 31, 2025. The effective tax rate for the three months ended March 31, 2026, reflects nondeductible compensation and tax credit. See Part I, Item 1 – Financial Statements, Note 7 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 September 30, 2025 and June 30, 2025 and the nine months ended September 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 March 31, 2026 and December 31, 2025.
Previous 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.
Current wording
Total average net production sold increased by 17 MBoe/d to 154 MBoe/d for the three months ended March 31, 2026 compared to 137 MBoe/d forthe three months ended December 31, 2025. The increase included 19 MBoe/d related to the addition of the Berry properties. Excluding the impact of the Berry production, our net production decreased by 1 MBoe/d primarily as a result of natural decline, offset by development results. Additionally our production-sharing contracts (PSCs), which are described below, negatively impacted our net oil production by 1 MBoe/d in the three months ended March 31, 2026 compared to the three months ended December 31, 2025.
Previous wording
Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts that are in effect through the economic life of the assets. The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs.
Current wording
Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of production and reserves to recover a portion of such capital and operating costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover certain capital and operating costs that we incur, (ii) for our share of contractually defined base production where applicable, and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and operating costs. However, our net economic benefit is greater when product prices are higher.
Previous wording
For further information on our production-sharing contracts, see Part I, Item 1 & 2 Business and Properties, Oil and Natural Gas Operations, Production, Price and Cost History in our 2024 Annual Report.
Current wording
The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. For further information on our production-sharing contracts, see Part I, Item 1 & 2 Business and Properties, Oil and Natural Gas Operations, Production, Price and Cost History in our 2025 Annual Report.
Previous wording
The following tables set forth the average realized prices and price realizations on the commodities we sell as a percentage of average Brent, WTI and NYMEX Henry Hub indexes for our oil and natural gas operations for the periods presented:
Current wording
The following table sets forth the average realized prices and price realizations (as a percentage of average Brent, WTI and NYMEX Henry Hub, as applicable) for the commodities we sell in the periods presented:
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. We expect first injection in 2026, subject to receipt of final regulatory approvals.
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. We recently completed construction of our first carbon capture project at our cryogenic gas processing facility and are preparing for first injection, subject to commissioning and final regulatory approval. We define carbon management expense to be our direct operating costs to run our carbon management segment.
Previous 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.
Current wording
The following table includes results for our carbon management segment for the three months ended March 31, 2026 and December 31, 2025.
Previous 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.
Current wording
Carbon management expenses decreased for thethree months ended March 31, 2026 compared to thethree months ended December 31, 2025 as a result of lower easement costs.
Previous wording
Our primary sources of liquidity and capital resources are cash flows from operations, available cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the three and nine months ended September 30, 2025 were for repurchases of our common stock, payment of dividends, and capital investments.
Current wording
Our primary sources of liquidity and capital resources are cash flows from operations, available cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the three months ended March 31, 2026 were for capital investments and payment of dividends.
Previous wording
(a)Excludes restricted cash of $16 million.
Current wording
(a)Excludes restricted cash of $15 million.
Previous wording
At current commodity prices and based upon our planned 2025 capital program described below, we expect to generate operating cash flow to return cash to shareholders through dividends and repurchases of our common stock. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or share repurchases to the extent permitted under our Revolving Credit Facility, our 8.25% senior notes due 2029 (2029 Senior Notes), and our 7.00% senior notes due 2034 (2034 Senior Notes) (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We continue to monitor the current macroeconomic environment and will adjust our planned uses of cash as necessary. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.
Current wording
At current commodity prices and based upon our planned 2026 capital program described below, we expect to generate operating cash flow to return cash to shareholders through dividends. 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.
Previous wording
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 Proceedsfor more information on our Share Repurchase Program.
Current wording
See Part I, Item 1 – Financial Statements, Note 9 Stockholders' Equityfor more information on our Share Repurchase Program.
Previous wording
See Part I, Item 1 – Financial Statements, Note 10 Stockholders' Equityfor more information on our dividends. See Part I, Item 1 – Financial Statements, Note 16 Subsequent Eventsfor information on an increased dividend declared in November 2025.
Current wording
See Part I, Item 1 – Financial Statements, Note 15 Subsequent Eventsfor information on a dividend declared in May 2026.
Previous wording
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. Of this amount, $250 million to $275 million is related to our oil and natural gas segment, $20 million to $40 million is for our carbon management segment and $10 million to $15 million is for corporate and other activities. The above amounts related to carbon management projects do not include amounts funded by Brookfield through the Carbon TerraVault JV, such as drilling injection and monitoring wells at our 26R reservoir.
Current wording
We entered 2026 with a capital program of $430 million to $470 million and have revised our 2026 capital program to a range of $520 million to $560 million. Of this amount, $500 million to $525 million is related to our oil and natural gas segment, $12 million to $20 million is for our carbon management segment and $8 million to $15 million is for corporate and other activities. The above amounts related to carbon management projects do not include amounts funded by Brookfield through the Carbon TerraVault JV, such as drilling injection and monitoring wells at our 26R reservoir.
Previous wording
Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the nine months ended September 30, 2025. See Part I, Item 1 – Financial Statements, Note 6 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 Debtin our 2024 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.
Current wording
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 three months ended March 31, 2026. 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 March 31, 2026 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debtin our 2025 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.
Previous wording
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.
Current wording
Cash flows from operating activities — For the three months ended March 31, 2026, our operating cash flow decreased by $87 million to $99 million from $186 million in the same period in 2025. This decrease in operating cash flow was primarily driven by changes in working capital.
Previous wording
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 $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.
Current wording
Oil production during the three months ended March 31, 2026 as compared to the same period in 2025 increased 13 MBbl/d from 111 MBbl/d to 124 MBbl/d as a result of the Berry Merger. Revenue increased as a result of the increases in production from the Berry Merger offset by lower average realized prices after derivative settlements. Average realized prices after derivative settlements for oil decreased by $2.64 per barrel to$69.37 in thethree months ended March 31, 2026 from$72.01 in the same prior year period. Our derivative settlements and premiums paid for the three months ended March 31, 2026 were$68 million, which was an increase of $40 million from$28 million in the same prior year period. Further, as a result of the Berry Merger, we experienced higher operating costs, employee costs, well abandonment costs, production taxes and greenhouse gas taxes during thethree months ended March 31, 2026 as compared to the same prior year period.
Previous wording
•government policy, war and political conditions and events, including the military conflicts in Israel, Lebanon, Ukraine and the Middle East;
Current wording
•government policy, war and political conditions and events, including the military conflicts in Israel and Ukraine and geopolitical uncertainty in the Middle East, including the current conflict in Iran, and Venezuela;
Previous wording
•the ability to successfully execute integration efforts in connection with the Aera Merger, and achieve projected synergies and ensure that such synergies are sustainable;
Current wording
•the ability to successfully execute integration efforts in connection with the Berry Merger, and achieve projected synergies and ensure that such synergies are sustainable;
Previous wording
•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;
Current wording
•the efforts of activists to delay or prevent oil and gas activities or the development of our carbon management segment through a variety of tactics, including litigation;
Previous wording
•changes in business strategy and our capital plan;
Current wording
•changes in business strategy and the ability and financial resources to execute our capital plan in a timely manner;
Previous wording
•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;
Current wording
•our ability to successfully identify, develop and finance carbon capture and storage projects, power projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and our ability to convert our MOUs and CDMAs to definitive agreements and enter into other offtake agreements;
Previous wording
•other factors discussed in Part I, Item 1A – Risk Factors of our 2024 Annual Report.
Current wording
•other factors discussed in Part I, Item 1A – Risk Factors.
Rearranged previous paragraphs (9)
Previous report — wording carried elsewhere
The following table presents our consolidated operating revenues for the periods indicated:
Previous report — wording carried elsewhere
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 report — wording carried elsewhere
Note: See Productionfor volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.
Previous report — wording carried elsewhere
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 report — wording carried elsewhere
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 report — wording carried elsewhere
Operating costs —The following table presents our operating costs for the nine months ended September 30, 2025 and September 30, 2024.
Previous report — wording carried elsewhere
For the nine months ended September 30, 2025 and September 30, 2024, other operating expenses, net includes the following:
Previous report — wording carried elsewhere
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 report — wording carried elsewhere
See Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debtin our 2024 Annual Report for information on the Revolving Credit Facility and related amendments. See Part I, Item 1 – Financial Statements, Note 16 Subsequent Eventsfor information on a recent amendment to our Revolving Credit Facility.