California Resources Corp (CRC) Business

Business

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.

Our business is organized into two reporting segments: oil and natural gas and carbon management. Our oil and natural gas segment explores for, develops and produces crude oil and condensate, natural gas liquids and natural gas in major producing basins located in California and Utah. As of December 31, 2025, our proved reserves totaled an estimated 654 MMBoe, of which 541 MMBbl were crude oil and condensate reserves, 37 MMBbl were NGL reserves and 455 Bcf, or 76 MMBoe, were natural gas reserves. As of December 31, 2025, we held approximately 2 million net mineral acres. Our operated asset base spans 68 distinct fields with approximately 22,000 net operated wells. We had average net production of approximately 138 MBoe/d (79% oil) for the year ended December 31, 2025.

Our carbon management segment, which we refer to as Carbon TerraVault, is focused on building, installing, operating and maintaining CO2 capture equipment, transportation assets and underground storage facilities. Our carbon management segment also owns an investment in the Carbon TerraVault JV. For more information on our segments, refer to Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Segment Results of Oil and Natural Gas Operations and Results of our Carbon Management Segment, and Part II, Item 8 – Financial Statements and Supplementary Data, Note 16 Segment Information.

Berry Merger

On September 14, 2025, we entered into an agreement to combine with Berry in an all-stock transaction. Berry was an independent energy company that owned oil-weighted, mostly conventional oil and natural gas fields in California and oil and natural gas fields in Utah that have the potential for unconventional development. The Berry fields in California are adjacent to or within the areas in which we operate. Through the Berry Merger, we added 56 MMBoe of proved developed reserves as well as C&J Well Services, one of the largest upstream well servicing and abandonment services businesses in California.

The Berry Merger closed on December 18, 2025 and we issued 5,572,115 shares of our common stock, which represented 0.0718 shares of our common stock for each outstanding share of Berry stock as of December 17, 2025. Immediately following the closing of the Berry Merger, the former Berry stockholders owned approximately 6% of CRC. In connection with the closing, Berry's outstanding debt was repaid and the underlying credit agreements were terminated. We repaid a significant portion of this indebtedness with proceeds from the issuance of our 2034 Senior Notes, which closed in October 2025. For more information on the Berry Merger, refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Business Combinations.

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.

7

Business Strategy

•Focus on integrating merger assets to capture synergies and continue reducing costs across our combined business. We are focused on reducing costs and improving operating efficiencies as a result of the Berry Merger. We are targeting annual run-rate synergies in the range of $80 million to $90 million within twelve months of the closing of the Berry Merger. We expect these synergies will come primarily from lower operating costs, general and administrative expenses and financing costs for the combined companies. In addition, we are pursuing other cost reduction efforts as part of our normal business processes.

•Maintain high standards of operational performance that create sustainable cash flows. We seek to maintain the highest standards of safety and operational integrity in the management of our assets, with the objective of sustaining long-term value and reliable cash flow generation. We believe that the strength and quality of our underlying assets, together with disciplined operational practices, position us to deliver durable financial results. For the year ended December 31, 2025, we generated $363 million of net income and $865 million of net cash provided by operating activities. We intend to continue prioritizing operational improvements in a safe, compliant, and environmentally responsible manner, recognizing that consistent execution is fundamental to financial performance.

•Focus on core E&P assets and pursue new opportunities. We are the largest operator in California and currently operate all of our core oil and gas fields. We intend to leverage this position and prioritize our strongest assets to simplify our operational structure and lower costs. We may have the opportunity to acquire additional producing assets at attractive valuations and could pursue other acquisitions that meet our financial, operational and regulatory criteria. In addition, we expect that the resumption of new well permitting in early 2026 will enhance our ability to develop our core assets in Kern County, which we believe will further strengthen our cash flows and position as the largest operator in California. Finally, we will continue to review non-core assets for potential divestment or alternative development opportunities where such actions are consistent with our strategic and capital allocation objectives.

•Maintain a disciplined and flexible capital program. We intend to maintain a disciplined and flexible capital program, allocating capital amongst our assets to maximize value in light of evolving regulatory and market conditions. Following the resumption of permitting for new wells in January of this year, we expanded our drilling program to include new well development in Kern County. We plan to pursue the development of new wells with attractive return profiles and payback periods of approximately three years across our portfolio. We expect to fund our capital program primarily from operating cash flows and maintain a flexible approach to adapt to fluctuations in commodity prices, permitting activity and broader regulatory developments.

•Preserve balance sheet strength and increase shareholder returns over time. We maintain a strong balance sheet and low leverage and continue to prioritize balance sheet protection. As of December 31, 2025, we had $1,401 million of liquidity, consisting of $1,284 million available for borrowing under the Revolving Credit Facility (after taking into account $176 million of outstanding letters of credit) and $117 million in available cash on hand. We had $1,300 million of long-term indebtedness as of the same date. By maintaining low leverage and ample liquidity, we believe we will be able to ensure a strong financial foundation that we expect will allow us to grow shareholder returns over time.

•Advance our carbon management solutions to lead the energy transition in California. We are focused on maximizing the value of our land, mineral and technical resources for decarbonization by developing CCS and other emissions reducing projects. In early 2026, we expect to capture emissions at our cryogenic gas plant at Elk Hills field for permanent sequestration. We are well positioned to provide industrial scale projects to help California meet its decarbonization goals and leverage our Carbon TerraVault JV with Brookfield to reduce our capital investments to develop these projects.

8

•Maintain our commitment to safety and environmental stewardship. Our commitment to health, safety and the environment (HSE) defines how we operate our business. We prepare our workforce to work safely through comprehensive training, safe work practices, technology and rigorous maintenance and asset integrity programs. In addition, we intend to continue efforts to reduce CO2 and methane emissions in our operations, proactively manage our idle wells and reduce our consumption of freshwater in our operations. We previously received MiQ’s certification of methane emissions for certain fields and expect to continue to seek third party certifications of our results and disclosure practices. Our commitment to these efforts is reflected in our management compensation metrics that include safety and environmental targets.

•Proactively engage with our legislators, regulators and the communities in which we operate. We seek to communicate effectively with legislators, regulators and state and local government and community leaders to ensure they understand the potential impacts of new legislation and regulations on our business and the state’s energy affordability, reliability and transition objectives. We strive to produce energy in a safe and responsible manner to help support and enhance the quality of life in the communities in which we operate.

Oil and Natural Gas Segment

The following table highlights key information about our oil and natural gas segment as of and for the year ended December 31, 2025:

(a)Our production includes oil, natural gas and NGL sales from fields added in the Berry Merger, which closed on December 18, 2025.

For a discussion of the regulatory issues affecting the development of our oil and natural gas properties, see Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities.

Basins in Which We Operate

San Joaquin Basin

Commercial petroleum development in the San Joaquin basin began in the 1800s. This resource rich basin in California contains multiple stacked formations throughout its areal extent, and we believe that this basin provides appealing opportunities for re-development of existing wells, as well as new discoveries and unconventional play potential. The geology of the San Joaquin basin continues to yield stratigraphic and structural trap discoveries.

9

The California oil fields added through the Berry Merger are located in the San Joaquin basin, including extensions of our existing Midway-Sunset, South Belridge and McKittrick fields, as well as additions adjacent to existing operations in Poso Creek and Round Mountain. Our largest fields in the San Joaquin basin include the Belridge and Elk Hills fields.

Belridge field: We operate and hold substantially all of the working, surface and mineral interests in the Belridge field, which consists of the North Belridge and South Belridge fields. The Belridge field consists of waterflood and steamflood operations. For the steamflood operations, we utilize natural gas that is both purchased from third parties and produced from our other fields. Our operations at Belridge include a central control facility with remote automation control on over 95% of the producing wells.

Elk Hills field: We operate and hold substantially all the working, surface and mineral interests in the Elk Hills field. Infrastructure includes efficient natural gas processing facilities, including a cryogenic gas plant, with a combined gas processing capacity of 330 MMcf/d, and a 550 MW cogeneration power plant that generates electricity to power our oil and gas operations at Elk Hills and other nearby producing fields. Our operations at Elk Hills also include a central control facility and remote automation control on over 95% of the producing wells.

Midway-Sunset field: We are a major operator and hold a significant portion of the working, surface and mineral interests in the Midway-Sunset field. The Midway-Sunset field consists of steamflood operations, in which we utilize natural gas that is both purchased from third parties and produced from our other fields.

We believe our extensive 3D seismic library, which covers over 900,000 acres in the San Joaquin basin, or over 60% of our gross mineral acreage in this basin, gives us a competitive advantage in field development.

Los Angeles Basin

This basin is a northwest-trending plain about 50 miles long and 20 miles wide located in California. Most of the significant discoveries in the Los Angeles basin date back to the 1920s. The Los Angeles basin has one of the highest concentrations per acre of crude oil in the world. We have significant operations in the Wilmington field, which is a large active oil field in this basin.

Most of our Wilmington production is subject to a set of contracts similar to production-sharing contracts (PSCs) 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. These PSCs represented 3% of our total production for the year ended December 31, 2025.

Sacramento Basin

California's Sacramento basin is a deep, thick sequence of sedimentary deposits of natural gas within an elongated northwest-trending structural feature covering about 7.7 million acres. Exploration and development in the basin began in 1918.

Uinta Basin

The Uinta basin consists mostly of mature light oil and natural gas fields covering more than 15,000 square miles with significant undeveloped resources. Exploration efforts immediately after the Second World War led to the first commercial oil discoveries in the Uinta basin. The application of improved hydraulic stimulation techniques in the mid-2000s greatly increased production from the Uinta basin.

10

We obtained approximately 100,000 net mineral acres in the Uinta basin in connection with the Berry Merger. We have an average working interest greater than 95% in these assets, and operations in the Brundage Canyon, Ashley Forest, Lake Canyon and Antelope Creek areas. A majority of our Utah acreage is on tribal lands and substantially all of it is held by production. The Uinta basin assets include both conventional and unconventional reserves. In addition to vertical well development, Berry completed four horizontal wells in 2025 and we are considering additional unconventional development.

We also have extensive gas infrastructure and available takeaway capacity in place to support additional development along with existing gas transportation contracts. We have natural gas gathering systems consisting of approximately 500 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. We also own a natural gas processing plant in the Brundage Canyon area located in Duchesne County, Utah with processing capacity of approximately 25 mmcf/d.

Other Basins

We have oil and natural gas operations in other basins in California, including the Ventura and Salinas basins. We also have mineral interests in undeveloped acreage throughout California, including the Santa Maria basin which is located in San Luis Obispo County and Santa Barbara County.

Mineral Acreage

The following table summarizes our gross and net developed and undeveloped mineral acreage as of December 31, 2025.

(a)Mineral acres spaced or assigned to productive wells.

(b)Total number of mineral acres in which interests are owned.

(c)Net mineral acreage includes acreage reduced to our fractional ownership interest and interests under our PSCs.

(d)Mineral acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether the mineral acreage contains proved reserves.

At December 31, 2025, 75% of our total net mineral interest position was held in fee and the remainder was leased. Of our leased acreage, approximately 77% is held by production and the remainder is subject to lease expiration if initial wells are not drilled within a specified period of time. The primary terms of our leases range from one to twenty years. The terms of these leases are typically extended upon achieving commercial production for so long as such production is maintained. Work programs are designed to ensure that the economic potential of any leased property is evaluated before expiration. In some instances, we may relinquish leased acreage in advance of the contractual expiration date if the evaluation process is complete and there is no longer a commercial reason for retaining the lease. In cases where we determine we want to take the additional time required to fully evaluate undeveloped acreage, we have generally been successful in obtaining extensions.

If we are not able to establish production or otherwise extend lease terms, approximately 6,000 net mineral acres will expire in 2026, 7,000 net mineral acres will expire in 2027 and 11,000 net mineral acres will expire in 2028. These leases represent 2% of our total net undeveloped acreage and 1% of our total net acreage as of December 31, 2025 and these expirations, should they occur, would not have a material adverse effect on us. Historically, we have not dedicated any significant portion of our capital program to prevent lease expirations and do not expect to do so in the future.

11

Title to Properties

As is customary in the oil and natural gas industry for acquired properties, we initially conduct a high-level review of the title to our properties at the time of acquisition. Individual properties may be subject to ordinary course burdens that we believe do not materially interfere with the use or affect the value of such properties. Burdens on properties may include customary royalty or net profits interests, liens incident to operating agreements and tax obligations or duties under applicable laws, or development and abandonment obligations, among other items. Prior to the commencement of drilling operations on those properties, we typically conduct a more thorough title examination and may perform curative work with respect to significant defects. We generally will not commence drilling operations on a property until we have cured known title defects that are material to the project. For additional information on properties that secure our debt, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt.

Production, Price and Cost History

The following table sets forth information regarding our production volumes, average realized and benchmark prices and operating costs per Boe (presented before and after hedges) for the periods presented. See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations for more information on our production and commodity prices. The Berry Merger and Aera Merger affect comparability of our production results between periods. For more information on the Berry Merger and the Aera Merger, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Business Combinations.

12

Oil, natural gas and NGL production for our two largest fields for the years ended December 31, 2025 and 2024 are presented in the table below:

Oil, natural gas and NGL production for our two largest fields for the year ended December 31, 2023 is presented in the table below:

Our operating costs include (1) variable costs that fluctuate with production levels and (2) fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. A certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program. However, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. We can quickly scale our operating costs in response to prevailing market conditions. We believe that a significant portion of our operating costs is variable over the lifecycle of our fields.

In line with industry practice for reporting PSCs, we report 100% of operating costs under such contracts in operating costs on our consolidated statements of operations as opposed to reporting only our share of those costs. We report the proceeds from production designed to recover our partners' share of such costs (cost recovery) in our revenues. Our reported production volumes reflect only our share of the total volumes produced, including cost recovery, which is less than the total volumes produced under the PSCs. This difference in reporting full operating costs but only our net share of production equally inflates our revenue and operating costs per barrel and has no effect on our net results.

The following table presents our operating costs after adjustment for excess costs attributable to PSCs for the periods presented:

(a)Operating costs, excluding effects of PSCs is a non-GAAP measure. As described above, 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. These amounts represent our operating costs after adjusting for this difference.

13

Estimated Proved Reserves and Future Net Cash Flows

The following tables summarize our estimated proved oil (including condensate), NGLs and natural gas reserves and PV-10 as of December 31, 2025. Our estimated volumes and cash flows were calculated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year (SEC Prices), unless prices were defined by contractual arrangements. For oil volumes, the average Brent spot price of $69.38 per barrel and WTI price of $65.34 per barrel were adjusted for gravity, quality and transportation costs. For natural gas volumes, the average NYMEX gas price of $3.39 per MMBtu was adjusted for energy content, transportation fees and market differentials. All prices are held constant throughout the lives of the properties. The average realized prices for estimating our proved reserves as of December 31, 2025 were $67.21 per barrel for oil, $45.81 per barrel for NGLs and $3.44 per Mcf for natural gas.

Estimated reserves include our economic interests under PSCs in our Long Beach operations in the Wilmington field. Refer to Part II, Item 8 – Financial Statements, Supplemental Oil and Gas Information for additional information on our proved reserves.

(a)As of December 31, 2025, approximately 10% of proved developed oil reserves, 6% of proved developed NGLs reserves, 7% of proved developed natural gas reserves and, overall, 10% of total proved developed reserves are non-producing. A majority of our non-producing reserves relate to steamfloods and waterfloods where full production response has not yet occurred due to the nature of such projects.

14

Changes to Proved Reserves

We added 93 MMBoe of proved reserves through the Berry Merger in 2025, including locations in the San Joaquin and Uinta basins. The components of the changes to our proved reserves during the year ended December 31, 2025 were as follows:

(a)Includes proved reserves related to PSCs of 51 MMBoe and 62 MMBoe at December 31, 2025 and 2024, respectively.

Revisions related to price – We had net negative price-related revisions of 25 MMBoe. Included in these revisions are negative price-related revisions of 37 MMboe, which were partially offset by 23 MMBoe of positive revisions. These negative revisions are primarily a result of lower average realized SEC Prices in 2025 as compared to 2024, including lower natural gas realizations in certain areas. These negative revisions were partially offset by positive revisions primarily from lower operating costs related to steamflood management.

Also included in the net negative price-related revisions are negative revisions of 12 MMBoe offset by 1 MMBoe of positive revisions, which were due the extension of the cap-and-invest program. The majority of these revisions were located in the San Joaquin basin. See Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities.

Revisions related to performance – We had 61 MMBoe of net positive performance-related revisions which included positive performance-related revisions of 80 MMBoe and negative performance-related revisions of 19 MMBoe. Our positive performance-related revisions primarily related to additional drilling activity in the San Joaquin basin, maintaining higher than forecasted base production, and extension of field life through steam management. Our negative performance-related revisions primarily were due to lower overall expected recovery from certain projects in the San Joaquin basin.

Extensions and discoveries – We added 3 MMBoe related to drilling in the San Joaquin basin.

Improved recovery – We added 27 MMBoe related to increased drilling activity associated with steamfloods in the San Joaquin basin.

Acquisitions and divestitures – We added 93 MMBoe related to the Berry Merger in the San Joaquin and Uinta basins.

15

Changes to Proved Undeveloped Reserves

The total changes to our proved undeveloped reserves during the year ended December 31, 2025 were as follows:

Revisions related to price – We had 1 MMBoe of net negative price-related revisions primarily resulting from lower average realized SEC Prices in 2025 as compared to 2024, including lower natural gas realizations in certain areas. Our negative price revisions of 2 MMBoe were partially offset by 1 MMBoe of positive revisions from lower operating costs.

Revisions related to performance – We had 16 MMBoe of net positive performance-related revisions primarily in the San Joaquin basin. Positive performance-revisions of 26 MMBoe were partially offset by 10 MMBoe negative revisions related to well performance and proved undeveloped reserves which were removed from our five year development plan in 2025.

Improved recovery – We added 27 MMBoe related to new projects associated with steamfloods in the San Joaquin basin.

Acquisition – We added 37 MMBoe in connection with the Berry Merger in the San Joaquin and Uinta basins.

Transfers to proved developed reserves – We converted 5 MMBoe of proved undeveloped reserves to proved developed reserves in the San Joaquin basin. This resulted in a conversion rate of 13% of our beginning-of-year proved undeveloped reserves, with an investment of $45 million in drilling and completion capital.

PV-10 and Standardized Measure

PV-10 of cash flows is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC Prices. Calculation of PV-10 does not give effect to derivative transactions. Our PV-10 is computed on the same basis as our standardized measure of future net cash flows, the most comparable measure under GAAP, but does not include the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. Standardized Measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing, costs and discount assumptions. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.

16

Reserves Evaluation and Review Process

Our estimates of proved reserves and related discounted future net cash flows as of December 31, 2025 were made by our technical personnel, comprised of reservoir engineers and geoscientists, with the assistance of operational and financial personnel and are the responsibility of management. The estimation of proved reserves is based on the requirement of reasonable certainty of economic producibility and management's funding commitments to develop the reserves. Reserves volumes are estimated by forecasts of production rates, operating costs and capital investments. Price differentials between specified benchmark prices and realized prices and specifics of each operating agreement are then applied against the SEC Price to estimate the net reserves. Operating and capital costs are forecast using the current cost environment applied to expectations of future operating and development activities related to the proved reserves. See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates for further discussion of uncertainties inherent in the reserve estimates.

Proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods, for which the incremental cost of any additional required investment is relatively minor. Proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.

Our Director of Reserves is the technical person who is primarily responsible for overseeing the preparation of our reserves estimates in compliance with the SEC rules and regulations. He has over 16 years of experience in the upstream oil and gas industry, with projects ranging from appraisal of primary production reservoirs to enhanced oil recovery methods. He holds a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines.

We have an Oil and Gas Reserves Review Committee (Reserves Committee), consisting of senior corporate officers, to review and approve our oil and natural gas reserves for 2025. The Reserves Committee annually reports its findings to the Audit Committee.

Audits of Reserves Estimates

Netherland, Sewell & Associates, Inc. (NSAI) was engaged to provide an independent audit of our reserves estimates for our fields located in California. For the year ended December 31, 2025, NSAI audited 81% of our total proved reserves.

DeGolyer and MacNaughton was engaged to provide an independent audit of our reserves estimates for the Uinta basin. For the year ended December 31, 2025, DeGolyer and MacNaughton audited 5% of our total proved reserves in the Uinta basin.

Our independent reserve engineers examined the assumptions underlying our reserves estimates, adequacy and quality of our work product and estimates of future production rates. They also examined the appropriateness of the methodologies employed to estimate our reserves as well as their categorization, using the definitions set forth by the SEC, and found them to be appropriate. As part of their process, they developed their own independent estimates of reserves for those fields that they audited. When compared on a field-by-field basis, some of our estimates were greater and some were less than the estimates of our independent reserve engineers. Given the inherent uncertainties and judgments in estimating proved reserves, differences between our estimates and those of our independent reserve engineers are to be expected. The aggregate difference between our estimates and those of the independent reserve engineers was less than 10%, which was within the Society of Petroleum Engineers (SPE) acceptable tolerance.

17

In the conduct of the reserves audits, our independent reserve engineers did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, crude oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if anything came to the attention of our independent auditors that brought into question the validity or sufficiency of any such information or data, they would not rely on such information or data until they had resolved their questions relating thereto or had independently verified such information or data. Our independent reserve engineers determined that our estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC as well as the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions. Our independent reserve engineers each issued an unqualified audit opinion on the applicable portions of our proved reserves as of December 31, 2025, which are attached as Exhibit 99.1 and Exhibit 99.2 to this Form 10-K and incorporated herein by reference.

NSAI qualifications – The primary technical engineer responsible for our audit is a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2006 and has over 6 years of prior industry experience. The primary geologist for our audit is a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 12 years of prior industry experience.

DeGolyer and MacNaughton – The primary technical engineer responsible for our audit is a Licensed Professional Engineer in the State of Texas, has Master of Science and Doctor of Philosophy degrees in Petroleum Engineering and has more than 10 years of experience in oil and gas reservoir studies and reserves evaluation.

18

Drilling Statistics

The following table sets forth information on our net exploration and development wells drilled and completed during the periods indicated, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. We refer to gross wells as the total number of wells in which interests are owned, including outside operated wells. Net wells represent wells reduced to our fractional interest. For information on our 2026 capital program, see Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Uses of Cash and for information on the California regulatory environment and our ability to obtain permits, see Regulation of the Industries in Which We Operate.

The following table sets forth information on our exploratory and development wells where drilling was either in progress or pending completion as of December 31, 2025.

Productive Wells

Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce at a reasonable rate of return. Our average working interest in our producing wells was 98% as of December 31, 2025. Wells are categorized based on the primary product they produce.

19

The following table sets forth our productive oil and natural gas wells (both producing and mechanically capable of production) as of December 31, 2025, excluding wells that have been idle for more than five years:

(a)The total number of wells in which interests are owned.

(b)Net wells include wells reduced to our fractional interest.

Exploration Inventory

We maintain a portfolio of exploration prospects in the San Joaquin basin, supported by an extensive library of 3D and 2D seismic data used to identify, evaluate and refine exploration opportunities. From time to time, we select exploration projects for investment when our business outlook and the prospect’s potential to advance our strategic objectives justify the associated risks.

Marketing Arrangements

Sales of our oil, natural gas and NGLs we produce are shown in the table below for the years ended December 31, 2025, 2024 and 2023. For more information on our revenues, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 15 Revenue.

Oil

We sell nearly all of our crude oil produced in California to local California refiners. A majority of our crude oil production is connected to third-party pipelines and California refining markets via our gathering systems. The majority of our production from our Uinta assets is sold to the Salt Lake City market, with some sold to the Gulf Coast market. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.

In 2025, the marketing arrangements for the majority of our production no longer rely on local postings but are instead based directly on Brent prices subject to applicable adjustments. International waterborne-based Brent prices are relevant because there is limited crude pipeline infrastructure available to transport crude overland from other parts of the United States into California. We believe that these limitations will continue to contribute to higher realizations in California than most other U.S. oil markets for comparable grades. The prices received for our Utah production have typically been based on local postings that are tied to WTI prices.

We have entered into derivative contracts to provide price protection for sales of produced oil. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Derivatives for more information on our Brent-based derivative contracts.

20

Natural Gas

We sell all of our natural gas not used in our operations into the California and Utah markets. A majority of these sales are made at index-based prices tied to SoCal Border pricing which can differ from NYMEX pricing. SoCal Border pricing reflects local market fundamentals, such as storage capacity and the availability of transportation capacity between the market and producing areas. Transportation capacity availability, transportation pricing, and gas processing prices in other areas may influence California prices because California imports nearly 95% of its natural gas from other states and Canada. We deliver our natural gas to customers using firm capacity contracts that have variable pricing on actual volumes shipped. Currently, we have sufficient capacity to ship our production volumes and we believe that we have the ability to enter into additional capacity agreements as needed.

In addition to selling natural gas, we also use natural gas in steam generation for our steamfloods and for power generation. We have entered into derivative contracts to provide price protection for the purchase of natural gas used in our steamflood operations. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Derivatives for more information on our natural gas derivative contracts.

NGLs

NGL prices vary by liquid type and realizations are closely correlated to the different commodity prices to which they relate. Prices can also fluctuate due to the demand for certain chemical products (for which NGLs are used as feedstock) and due to infrastructure constraints and seasonality. Finally, our results are also affected by the performance of our natural gas-processing plants. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the remaining products as NGLs. The efficiency with which we extract liquids from the wet gas stream affects our production volumes and operating results. Our natural gas-processing plants also facilitate access to third-party delivery points near the Elk Hills field.

We currently have a pipeline transportation contract to ship approximately 6,000 barrels per day of NGLs through March 2026. Our contract to transport NGLs requires us to cash settle any shortfall between the contractual throughput minimums and volumes actually shipped. We expect to continue to meet all our throughput minimums under this contract.

Delivery Commitments

We have commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. As of December 31, 2025, we had delivery commitments as shown in the table below.

We expect to fulfill our delivery commitments predominantly from producing our proved developed reserves and to a lesser extent from third party volumes acquired in connection with our marketing activities. We typically enter into index-based contracts with prices set at the time of delivery.

Our Principal Customers

We primarily sell crude oil, natural gas and NGLs to California refineries, marketers and other purchasers that have access to transportation and storage facilities.

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. In January 2026, Valero confirmed its 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.

21

Following the closure of the Phillips 66 refinery, and assuming Valero's Benicia refinery ceases operations, six major petroleum refineries will 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. However, the ability of producers to access the entirety of this refining capacity would be limited by available pipeline transportation and in-take constraints at individual refineries. Based on currently available refining capacity and our flexibility in marketing our crude oil production, we do not expect that a cessation of operations at these refineries, including the Valero Benicia refinery, would have a material adverse effect on our ability to market our crude oil.

In December 2025, crude oil shipments on the San Pablo Bay Pipeline – the primary inland pipeline carrying crude from California fields to Bay Area refiners – were effectively suspended after refinery demand declined and producers ceased nominations, reducing volumes to zero. The closure of this pipeline effectively eliminated our access to Bay Area refineries and we modified our marketing, transportation and shipping arrangements to reach alternative markets in Southern California. As a result, we expect to experience higher transportation costs as well as greater reliance on southbound transportation capacity. These effects are likely to continue for as long as the suspension of pipeline flow persists, and could persist should the pipeline be permanently idled. In addition, any significant increase in in-state crude oil production, including from offshore platforms, could further stress available transportation capacity and negatively impact price realizations. At this time, we cannot predict whether or when crude shipments on the San Pablo Bay Pipeline will resume.

The loss of refineries in the Bay Area and related pipeline transportation capacity and any additional closures in the future could increase our transportation costs and negatively impact realizations and materially adversely affect our business, financial condition, results of operations or cash flow.

Our ability to sell our products can be affected by a variety of factors that are beyond our control. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 1 Nature of our Business, Summary of Significant Accounting Policies and Other for more information on our customers.

Competition

Our competitors are primarily other exploration and production companies that produce oil, natural gas and NGLs. We compete locally against independent producers and a major international oil company which operate in California. We also compete with foreign oil and gas companies since California imports over 75% of the oil it consumes and nearly 95% of its natural gas needs. We believe that our proximity to the California refineries gives us a competitive advantage over importers due to lower transportation costs. Further, California refineries are generally designed to process crude with characteristics similar to those of our production. However, efforts to construct new interstate pipelines to transport refined products or to increase waterborne imports of refined products, if successful, could alter local supply dynamics and affect competitive conditions in our market. The California natural gas market is serviced from a network of pipelines, including interstate and intrastate pipelines.

In Utah, we compete locally against independent producers that operate in the area. Additionally, we compete to transport our oil to refineries within Utah. Competition for pipeline and transportation capacity, including access to interstate pipelines and rail facilities, may affect realized pricing and basis differentials.

We compete for third-party services in California and Utah to profitably develop our assets, to find or acquire additional reserves, to sell our production and to find and retain qualified personnel. The regulatory environment in California could negatively impact the number of oil field service providers, drilling and workover rigs, pipe and other oil field equipment in the state. We have not experienced shortages or delays in the delivery of materials or services from our vendors in either California or Utah.

22

Carbon Management Segment

Our carbon management segment, which we refer to as Carbon TerraVault, pursues the development of carbon capture and sequestration projects. We expect that our Carbon TerraVault CCS projects will inject CO2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO2 deep underground. We also expect to invest in projects that rely on CCS technology in connection with reducing our own emissions, including a project at our cryogenic gas processing plant discussed below. In addition, we may participate in the development of projects that are the source of these CO2 emissions.

CCS Permitting

In December 2024, the EPA issued Class VI permits, the first permits issued in California, for underground injection and storage of CO2 into the 26R reservoir which is located at our Elk Hills field. The permits became effective on February 6, 2025. The 26R reservoir is part of our Carbon TerraVault JV as discussed further below.

We have submitted permit applications with the EPA for another permanent sequestration project at our Elk Hills field, four permanent sequestration projects in the Sacramento basin and two permanent sequestration projects in Central California that are under review by the EPA. We acquired one permit application with the EPA for sequestration projects in the Belridge field as part of the Aera Merger.

The timing, review and approval of our permit applications by the EPA are uncertain and we can give no assurances that these permit applications will be reviewed and approved in a timely manner or at all.

CCS Projects

We recently completed construction of carbon capture equipment at our cryogenic gas processing facility at the Elk Hills field and are currently commissioning the facility. This project which will remove CO2 from inlet gas for injection into the nearby 26R storage reservoir (owned by the Carbon TerraVault JV) in spring 2026, subject to EPA approval. We expect this project will increase operational efficiency of the cryogenic gas processing plant, improve propane recovery from inlet gas, and reduce the carbon intensity of the electricity generated at our Elk Hills power plant.

We expect that the size and scope of projects providing for the capture of emissions will continue to grow as we develop our carbon management segment. We expect to minimize the amount of capital we spend on these projects through partnerships and joint ventures, including the Carbon TerraVault JV. For more information about the risks involved in our carbon management segment, see Part I, Item 1A – Risk Factors.

Carbon TerraVault JV

In August 2022, we entered into a joint venture with Brookfield. We hold a 51% interest in the Carbon TerraVault JV and Brookfield holds a 49% interest. Our initial contribution included rights to inject CO2 into the 26R reservoir in our Elk Hills field for permanent CO2 storage. Brookfield has contributed $92 million to date. The remaining amount of Brookfield's initial investment is based on the permitted storage capacity, subject to certain contractual adjustments. This remaining amount will be contributed to the joint venture upon entering into contracts for the injection of specified volumes with respect to the 26R reservoir. The parties have certain put and call rights with respect to the 26R reservoir if certain milestones are not met.

Both Brookfield and CRC have granted the other party a right to participate in projects that involve the capture, transportation and storage of CO2 in California. These projects may be developed throughout the Carbon TerraVault JV or other joint ventures. This right expires upon the earlier of (1) August 2027, (2) when a final investment decision has been approved by the investment committee of the Carbon TerraVault JV for storage projects representing in excess of 5 million metric tons per annum (MMTPA) in the aggregate, or (3) when Brookfield has made contributions to the joint venture in excess of $500 million (unless Brookfield elects to increase its commitment). The non-presenting party has the option to accept, decline or defer its decision to participate. If the decision is deferred, then the presenting party may continue to pursue development; however during this time and prior to a final investment decision, the non-presenting party may elect to participate provided they pay their share of the project development costs incurred up to that point. The joint venture does not have a definitive term and terminates upon either party holding all of the ownership interests in the joint venture.

23

Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Investments and Related Party Transactions for more information on our Carbon TerraVault JV.

Competition

We compete with other potential storage providers to acquire and develop storage reservoirs and enter into agreements with existing and future emission sources.

Responsible Net Zero Goal

In May 2025, our Board of Directors adopted the following net zero emissions goal (Responsible Net Zero):

Our goal is to achieve at least an 80% reduction of absolute Scope 1 and 2 greenhouse gas emissions and neutralize the remaining Scope 1 and 2 emissions to achieve Net Zero by 2045. Our near-term ambition is to achieve a 20% reduction in the average carbon intensity of all CRC oil and gas production by 2035, thereby reducing our customers’ Scope 3 emissions. We are committed to responsibly producing energy in a manner consistent with the UN’s Sustainable Development Goals.

Our Responsible Net Zero goal is based on the following considerations:

•We use 2020 total Scope 1 and 2 GHG emissions (including those of Aera) as our baseline to measure progress towards our Responsible Net Zero goal. Our emissions are based on calculations reported to the California Air Resources Board (CARB).

•The term “neutralize” as it relates to Scope 1 GHG emissions refers to the planned use of either carbon offsets generated and claimed internally or carbon offsets purchased and claimed through the third party carbon market (including California’s Cap-and-Trade Program). For Scope 2 GHG emissions, the term “neutralize” refers to the use of contractual instruments such as renewable energy certificates or carbon offsets.

•The term “carbon offsets” refers to greenhouse gas emission reductions arising from third-party certified projects that remove, reduce, or avoid GHG emissions from the atmosphere.

•References to UN Sustainable Development Goals (UN SDGs) refer primarily to goals regarding income inequality, biodiversity, corruption, Scope 1 and 2 GHG emissions carbon intensity, fair labor and gender treatment. Operating a business consistent with UN SDGs is inherently a subjective determination regarding which UN SDGs to prioritize, how to weigh such matters against commercial considerations and to what extent a business activity promotes or is consistent with a given UN SDG.

•Future acquisitions and divestitures, as well as changes to methodology in accounting for carbon emissions or adjustments to historical carbon calculations as well as the use of third-party data or validation processes, could cause us to change our Responsible Net Zero goal.

•Assumptions, estimates, goals and similar statements and concepts regarding our Responsible Net Zero goal contain or assume forward looking statements within the meaning of federal securities laws and are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. For a discussion of these risks and uncertainties, please refer to the Risk Factors and Forward-Looking Statements described in our Annual Report on our most recent Form 10-K and any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K filed with the United States Securities and Exchange Commission.

Our Responsible Net Zero goal replaces our previously adopted Full Scope Net Zero goal. This change was primarily driven by the impact of the Aera Merger, which nearly doubled the size of our asset base and impacted the overall carbon intensity of our operations. The continuing lack of regulatory clarity around the measurement of Scope 3 GHG emissions (including the impact of carbon capture and sequestration in such calculations) also contributed to this change.

24

Infrastructure

Our infrastructure includes the plants and facilities shown in the table below.

(a)Includes 120 MW attributable to our 50% interest in the Midway Sunset Power Plant. Does not include the Long Beach Unit Power Plant described below or microturbines that generate limited power.

Power Generation Assets

We own and/or operate power generation facilities with a combined 855 MW of capacity. A material portion of the electrical output of these facilities is used in our oil and natural gas operations at nearby fields. Generating capacity that is not used in our operations is offered into the California Independent System Operator (CAISO) wholesale power market. We enter into resource adequacy capacity contracts with load-serving entities which are tasked with ensuring there is sufficient available generating capacity to support their forecasted customer energy demand. Our contracts for resource adequacy are at market prices and generally for a term that does not exceed twelve months. The actual electrical output of our power generating facilities varies over time based on operating conditions, pricing and other conditions. Our significant power generating facilities are described below.

San Joaquin Basin

Elk Hills Power Plant – We own a 550 MW combined-cycle cogeneration power plant, located adjacent to the Elk Hills natural gas processing facility. The plant runs at varying levels based on power pricing and other market conditions.

The Elk Hills power plant supplies electricity to Elk Hills field and the power needs of the field remain relatively constant throughout the year. Because the output of the plant varies, we expect approximately 25% to 60% of the electricity generated in 2026 will be used in our oil and natural gas operations. The remaining facility capacity is available to the resource adequacy market and is offered to the CAISO wholesale market.

25

Midway Sunset Cogeneration Facilities

•We own a 50% interest in a 240 MW cogeneration power plant located in the Midway Sunset field in Kern County and the remaining 50% is held by San Joaquin Energy Company, a subsidiary of NRG Energy, Inc. Our investment in this joint venture is accounted for using the equity method of accounting as discussed in Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Investments and Related Party Transactions. The electricity generated by this plant is sold to CAISO and the facility also participates in the resource adequacy capacity market.

•Following the Berry Merger, we own three natural gas burning cogeneration plants, each located in the Midway Sunset field in Kern County, that produce electricity and steam. These include a 36 MW facility, an 18 MW facility, and a 5 MW facility. We use a portion of the electricity generated by these cogeneration facilities to support our oil and natural gas operations in the area. Excess electricity is either sold to a California public utility under a power purchase agreement that expires in November 2026 or offered to the CAISO and the resource adequacy capacity market.

Belridge Power Plant – We own a 62 MW cogeneration power plant located in the Belridge field in Kern County, California. The electricity generated by this plant is used in our operations.

Los Angeles Basin

Long Beach Unit Power Plant – We operate a 48 MW power generating facility that is owned by the Long Beach Unit in the Wilmington field. The electricity generated by this plant is used in our operations.

In addition, we own and/or operate a number of smaller gas-fired power plants that are primarily used to

generate power for our oil and natural gas operations.

Other Infrastructure Assets

Gas processing infrastructure used in our oil and gas segment includes the Elk Hills cryogenic gas plant with a capacity of 200 MMcf/d of inlet gas and one low temperature separation plant used as a backup facility. Our natural gas processing facilities are interconnected via pipelines to nearby third-party rail and trucking facilities, with access to various North American NGL markets. In addition, we have truck rack facilities coupled with a battery of pressurized storage tanks at our natural gas processing facilities for NGL sales to third parties. We own, control and operate water management and steam-generation infrastructure. We soften and self-supply water to generate steam, reducing our operating costs. This is integral to our oil and natural gas operations in the San Joaquin basin. Our tank storage capacity throughout California gives us flexibility for a period of time to store crude oil and NGLs, allowing us to continue production and avoid or delay any field shutdowns in the event of temporary power, pipeline or other shutdowns. Our pipelines are dedicated almost entirely to collecting our oil and natural gas production and are in close proximity to field-specific facilities such as tank farms or central processing sites. Our oil pipelines connect to multiple third-party transportation pipelines. In addition, virtually all of our natural gas facilities connect with major third-party natural gas pipeline systems.

We also own a natural gas processing plant in the Brundage Canyon area located in Duchesne County, Utah with capacity of approximately 25 MMcf/d. We have natural gas gathering systems consisting of approximately 500 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. We also have extensive gas infrastructure and available takeaway capacity in place to support additional development along with existing gas transportation contracts. This facility takes delivery from gathering and compression facilities we operate.

Human Capital Management

We had approximately 2,500 employees as of December 31, 2025, as compared to approximately 1,550 as of December 31, 2024, all of whom were located in the United States. The significant growth in headcount of approximately 990 employees relates to the Berry Merger that closed in December 2025. Approximately 640 of these employees are employed by our subsidiary C&J Well Services. Approximately 250 of our employees are covered by a collective bargaining agreement. We also utilize the services of many third-party contractors throughout our operations.

26

Development

We provide various employee development opportunities to enhance leadership growth and expand career opportunities. Our employees undergo mandatory annual training on our policies including health and safety, business ethics, harassment, IT security and others. In addition to training, our employees receive regular performance and career development discussions from their direct managers. We utilize an annual performance review process for all employees.

Culture and Engagement

Our goal is to foster an open and welcoming culture and we are committed to advancing a workplace culture that is hospitable to all backgrounds and perspectives. We believe this encourages workforce engagement and leads to more thoughtful and innovative business decisions.

Safety and Environmental Stewardship

Our unwavering commitment to health, safety and the environment defines how we operate our business. We prepare our workforce to work safely through comprehensive training, safe work practices, technology and rigorous maintenance and asset integrity programs. Each year, we set thresholds for TRIR and gross barrels spilled as quantitative metrics that directly impact incentive compensation for all of our employees. We registered a workforce TRIR of 0.40 and recorded 1,124 gross barrels of production fluids spilled in 2025, excluding Berry operations. We have achieved exemplary safety performance over the last several years by promoting a culture of safety where all employees, contractors and vendors are empowered with Stop Work Authority to cease any activity – without repercussions – to prevent a safety or environmental accident.

Engagement and Retention

We survey our employees annually to ensure employee sentiment is collected and heard each year allowing us to assess engagement levels and drivers to determine areas of improvement to enhance engagement and retention. The results of the engagement surveys are reviewed by senior management and our Board of Directors. Senior leadership also hosts regular townhalls so employees can engage with them through question-and-answer sessions.

Reorganization

In February 2026, we undertook a reduction in force following the Berry Merger that resulted in a reduction of our headcount and we expect to recognize a charge of approximately $22 million in other operating expenses, net on our condensed consolidated statement of operations for the three months ended March 31, 2026, which primarily includes severance.

Seasonality

Certain of our operating costs and the prices for our products fluctuate throughout the year. For example, prices for natural gas (that we both market to third parties and purchase for use in our operations) tend to be higher in the winter and summer months. However, seasonality overall does not have a material effect on our earnings during the year.

Our operations have been, and in the future could be, impacted by winter weather conditions, especially in Utah, and by electrical storms and high temperatures in the spring and summer, as well as by wildfires and rain.

27

Regulation of the Industries in Which We Operate

Our operations are subject to a wide range of federal, state and local laws and regulations. Those that specifically relate to oil and natural gas exploration and production and carbon sequestration, utilization and storage are described in this section. CalGEM is the primary regulator of the oil and natural gas production industry in California and the California State Lands Commission provides additional administration of the state’s surface and mineral interests. With respect to our assets in Utah, we operate under leases regulated by federal agencies, including the Bureau of Land Management (BLM), as well as on lands regulated by the Utah Division of Oil, Gas and Mining.

Regulation of Exploration and Production Activities

Well Permitting

During 2025, we continued to experience delays from CalGEM in obtaining new well, sidetrack, deepening and workover permits. These delays resulted from a combination of more stringent environmental review requirements, limited agency resources and policy directives outside of our control. During 2025, we (including our Berry subsidiary) received permits for 506 workovers, six deepenings and 346 sidetracks, and no permits for new oil and gas wells.

CalGEM resumed issuing permits for new oil and gas wells beginning in January 2026 following the enactment of Senate Bill 237. As of January 31, 2026, we had received 16 permits for new oil and gas wells and expect to receive additional permits during the course of the year. We also expect the issuance of workover, deepening and sidetrack permits to increase throughout 2026.

We currently hold sufficient permits to undertake a majority of our 2026 capital program. Now that CalGEM has resumed issuing permits through the Kern County EIR process, we expect to obtain additional new well permits for the remainder of our 2026 capital program on a timely basis. See Liquidity and Capital Resources for more information. For more information on our permitting risks, see Part 1, Item IA – Risk Factors – Risks Related to Regulation and Government Action, We may face material delays related to our ability to timely obtain permits necessary for our operations or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments.

Kern County EIR Litigation

Since June 2022, our oil and gas drilling activities have been significantly impaired as a result of litigation by certain environmental activists. This litigation primarily challenged Kern County’s adoption of an ordinance that provided for the countywide development of oil and natural gas wells on the grounds that the Environmental Impact Report (EIR) prepared by the county for the project failed to satisfy the requirements of CEQA. The litigation resulted in numerous court rulings, orders and appeals. Following the enactment of SB 237 as described below, the trial court issued an order on the merits of the case that lifted the stay that had effectively prevented the issuance of new well drilling permits in Kern County. The deadline for appeals passed on February 2, 2026, with no appeal filed. Developments in the enactment of SB 237 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.

Regulatory Activity

In recent years, the California Legislature and Governor have significantly expanded the jurisdiction, duties and enforcement authority of CalGEM, the State Lands Commission and other state agencies with respect to oil and natural gas activities through legislation and policy pronouncements. CalGEM’s responsibilities now include public health and safety and the reduction or mitigation of greenhouse gas emissions while meeting the state’s energy needs. The scope and limits of this expanded authority, and the manner in which it may be exercised, remain subject to interpretation and legal challenge, creating uncertainty regarding certain aspects of oil and natural gas operations in California. For example, CalGEM published a rulemaking, effective in 2024, prohibiting well stimulation treatment in connection with oil production. Prior to the rulemaking, CalGEM denied certain well stimulation treatment permits in Kern County (as part of the well stimulation treatment permitting phase out). The legality and validity of CalGEM’s denial of such permits is subject to challenge, with litigation pending at this time. Along with other plaintiffs, we are seeking declaratory and other relief.

28

CalGEM is also required to study and prioritize idle wells with emissions, evaluate abandonment and restoration costs, and review and adjust bonding requirements. CalGEM and other state agencies have also significantly revised their regulations, regulatory interpretations and data collection and reporting requirements.

In addition, certain local governments have proposed or adopted ordinances that would restrict certain drilling activities in general, including by imposing setback distances, limiting well stimulation, completion or injection activities, or banning certain operations outright. Other local governments have also sought to ban natural gas or the transportation of natural gas through their cities.

Senate Bill 237 (Oil and Gas Permitting)

Senate Bill 237 (SB 237), enacted in September 2025, implements a number of changes to help facilitate new and continued oil and gas production in Kern County. Among other provisions, SB 237 deems Kern County’s Second Supplemental EIR (SSEIR) sufficient for full compliance with the requirements of the California Environmental Quality Act (CEQA). Projects that satisfy the SSEIR, certified pursuant to the Kern County Oil and Gas Ordinance, are deemed sufficient and no further environmental review or additional mitigation measures are required. The provisions of SB 237 became effective as of January 1, 2026, and allow for the issuance of up to 2,000 new drill wells per year for up to ten years in Kern County. We believe that the adoption of SB 237 will support operational continuity and investment planning by California’s oil and gas industry and, due to the increased clarity around permitting standards, will help enhance long-term development opportunities in Kern County, benefiting our asset base located in the region.

Assembly Bill 1207 (Cap-and-Invest Extension)

Assembly Bill 1207 (AB 1207), enacted in September 2025, extends California’s greenhouse gas cap-and-invest program through 2045, providing long-term policy certainty for covered entities under the Program. The legislation also establishes emission reduction initiatives, enhanced reporting requirements and 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 adopt implementing regulations regarding the safe transportation of CO₂ in pipelines by July 1, 2026, establishing a pathway to lifting the current moratorium on the construction and operation of new CO₂ pipeline operations in the state. The legislation mandates stringent design, routing, and disclosure standards consistent with or exceeding a proposed revision to federal requirements under the Pipeline and Hazardous Materials Safety Administration that was subsequently withdrawn prior to federal enactment (Draft PHMSA Regulations). Under SB 614, CO₂ pipelines within a single facility and for which construction was permitted before July 1, 2025, shall not be required to subsequently comply with those regulations that pertain to design and construction if the pipeline is constructed to meet the standards of the Draft PHMSA Regulations. The CO₂ pipelines comprising our Carbon Terra Vault I (CTV I) project at our Elk Hills field were permitted prior to July 1, 2025, and have been constructed to meet the standards of the Draft PHMSA Regulations. Upon implementation, SB 614 is expected to help enable the development of carbon-capture and storage projects that rely upon capture of carbon dioxide from an emission source that is remote from the facility into which the emissions will be sequestered.

29

Pipeline Transportation

Federal and state pipeline regulations have also been revised by both CalGEM and the Office of the State Fire Marshal over recent years, including requirements relating to integrity management, risk assessments, and spill prevention, amongst others. Additionally, PHMSA has, from time to time, issued new regulations expanding or otherwise revising pipeline integrity requirements. For example, in January 2025, PHMSA released a final rule enhancing requirements for detecting and repairing leaks on new and existing natural gas distribution, gas transmission and gas gathering pipelines. However, the current administration withdrew the final rule and, accordingly, it has not been codified. Prior to that, in September 2023, PHMSA published a proposed rule that would enhance the safety requirements for gas distribution pipelines and would require updates to distribution integrity management programs, emergency response plans, operations and maintenance manuals, and other safety practices. The Federal Register indicates that PHMSA is analyzing comments to the proposed rule through December 2026.

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 were not collected. Although the underlying statute still requires a methane charge, An Act to Provide for Reconciliation Pursuant to Title II of H. Con. Res. 14th and commonly referred to as the One Big Beautiful Bill Act, postponed implementation from 2024 to 2034.

Water Injection

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. The next phase of reduction continues to be on hold 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.

Activism

Opposition toward oil and gas drilling and development activity has been growing over time. Companies in the oil and gas industry are often the target of efforts to delay or prevent oil and gas development by non-governmental organizations and individuals. This opposition also extends to our carbon management segment as certain activists oppose carbon capture and sequestration efforts by the oil and gas industry. These activists use a variety of tactics that primarily rely on allegations regarding safety, environmental compliance and business practices. At both the state and federal level, these tactics include seeking changes to laws, pressuring governmental agencies to promulgate regulations or engage in rulemaking, or pursuing litigation.

For example, in November 2024, environmental groups collectively filed CEQA litigation against Kern County alleging CEQA violations in connection with the County’s approval of conditional use permits for our CTV I project at our Elk Hills Field. At this time, we cannot predict the outcome of this challenge with any certainty. Such lawsuits have the potential to delay timely construction of our CCS projects and commencement of operations and could otherwise have a material adverse effect on our business, results of operations and financial condition. Please see Regulation of Carbon Capture, Sequestration and Storage – CCS Project Permitting below for additional information.

30

Regulation of Health, Safety and Environmental Matters

Numerous federal, state, local and other laws and regulations that govern health and safety, the release or discharge of materials, land use or environmental protection may restrict the use of our properties and operations, increase our costs or lower demand for or restrict the use of our products and services. Applicable federal health, safety and environmental laws include the Occupational Safety and Health Act, Clean Air Act, Clean Water Act, Safe Drinking Water Act, Oil Pollution Act, Natural Gas Pipeline Safety Act, Endangered Species Act, Migratory Bird Treaty Act, Comprehensive Environmental Response, Compensation, and Liability Act, Resource Conservation and Recovery Act and the National Environmental Policy Act (NEPA), among others. California imposes additional laws that are analogous to, and often more stringent than comparable federal laws.

These laws and regulations, among other things:

•establish air, soil and water quality standards and require monitoring, reporting and attainment plans that may include mitigation measures or restrictions on development or operations in certain regions, including the San Joaquin Valley;

•require permits, approvals and mitigation measures before drilling, workover, production, underground injection, waste disposal or facility construction activities may commence;

•require the installation and operation of safety systems and pollution control equipment, including leak detection, monitoring, inspection, maintenance and repair programs;

•restrict the use of water, land, habitat and other natural resources and impose conservation, reclamation, energy efficiency or renewable energy requirements;

•regulate the generation, handling, storage, transportation and disposal of solid and hazardous wastes, including requirements related to well plugging and abandonment and facility decommissioning;

•limit or prohibit operations in certain protected areas or require habitat conservation or land dedication;

•impose liabilities, including strict or joint and several liability, for unauthorized releases or discharges of regulated materials;

•impose taxes, fees or other charges related to environmental compliance;

•require environmental analyses, recordkeeping and reporting; and

•may expose us to administrative proceedings, civil litigation or enforcement actions by governmental authorities or third parties.

Compliance with these requirements can restrict operations or increase costs. For example, California continues to regulate underground injection activities under the Safe Drinking Water Act, including through ongoing coordination among CalGEM, the State Water Resources Control Board and the U.S. Environmental Protection Agency (EPA) regarding aquifer exemptions and well integrity. While a significant number of aquifer exemption applications have been approved, certain applications remain subject to additional technical review, and permitting timelines and conditions may continue to evolve. These processes have resulted, and could continue to result, in permit delays, operational restrictions or additional compliance costs.

At the federal level, the scope and application of NEPA requirements remain uncertain. Following the change in presidential administration, the Council on Environmental Quality (CEQ) rescinded all of its regulations implementing NEPA and withdrew its interim guidance on the consideration of greenhouse gas emissions and climate change under NEPA. In September 2025, the CEQ issued new guidance to federal agencies implementing NEPA, encouraging agencies to limit their NEPA reviews, rely more heavily on sponsor-prepared documents, and streamline the NEPA process. Subsequently, several agencies have made significant changes to their NEPA rules and procedures. As a result of these changes, the standards and procedures governing environmental review of federal actions, including oil and natural gas activities on federal lands, remain in flux and may result in delays or additional analysis requirements.

31

There is also uncertainty regarding the availability and timing of certain federal funding programs. In early 2025, the federal government temporarily paused and subsequently resumed disbursement of certain grants and loans appropriated under the Inflation Reduction Act and the Infrastructure Investment and Jobs Act while undertaking a broader review of federal spending processes. Although these actions did not alter statutory tax credit provisions, any future disruption, delay or withdrawal of federal funding could adversely affect the development, timing or economics of projects in which we or our counterparties participate.

California continues to implement policies addressing water scarcity and drought conditions that may restrict groundwater extraction or increase water costs. Water management, including our ability to recycle, reuse and dispose of produced water, and to access third-party water supplies on commercially reasonable terms and in compliance with applicable laws and permits, is critical to our operations. We treat and reuse water produced in our operations for pressure management, waterflooding, steamflooding and drilling activities, and we also supply reclaimed produced water to certain agricultural users. We additionally rely on water from local and regional suppliers, including for power generation and steam operations. While our operations have not to date been materially impacted by restrictions on third-party water supplies, future limitations or increased costs could adversely affect our operations.

Federal, state and local agencies may assert overlapping jurisdiction in these areas, and certain laws and regulations may apply retroactively. These regimes may impose liability on us for past conditions or activities, including those attributable to prior owners or operators, regardless of fault or the legality of the original conduct.

Regulation of Carbon Capture, Sequestration and Storage

Unitization Senate Bill No. 905

Senate Bill No. 905 (SB 905), enacted on September 16, 2022, contemplates the development of unitization, permitting and pipeline safety regulations over a multi-year period to facilitate the development of CCS projects in California, though the legislation does not provide for compulsory unitization. Senate Bill No. 905 also provides for a unified permitting process to simplify the permitting process for CCS projects, although this will be optional for project applicants. Additionally, the law contemplates the implementation of a new regulatory program incorporating standards that are not yet defined and that could affect the timing of future CCS projects in California. The California Air Resources Board has been tasked with developing this proposed framework and this work is still pending at this time. We believe that our Carbon TerraVault projects will continue to be developed on a timeline consistent with our initial expectations as these initial projects are not reliant on the unitization or permitting regulations being developed under Senate Bill No. 905.

Pipelines and Senate Bill No. 614

Our CO₂ pipelines comprising our CTV I project are subject to Senate Bill No. 614, discussed in more detail above.

CCS Project Permitting

On October 21, 2024, the Kern County Board of Supervisors approved the issuance of the conditional use permits and certified the EIR for our first CCS project, Carbon TerraVault I (CTV I). On November 22, 2024, a group of non-governmental organizations filed suit against the County of Kern and its Board of Supervisors, challenging the certification of the EIR alleging non-compliance with CEQA. In addition to challenging the EIR, the Petitioners stated their intention to seek injunctive relief for a stay of the project, but to date have not yet sought such relief. This litigation is ongoing, and we cannot predict the outcome of this litigation with certainty.

The EPA issued Class VI underground injection control (UIC) permits for the construction and operation of four CO2 injection wells at the site of the CTV I 26R underground CO2 storage reservoir at our Elk Hills Field. The EPA’s permits became effective February 3, 2025.

Construction and testing of our first two Class VI wells is complete, and final modifications and testing are being conducted at our Elk Hills Field. We anticipate the first CO2 injection at these sites in spring 2026.

As of February 28, 2026, we have eight Class VI UIC project applications related to our carbon management segment pending with the EPA in different stages of the permitting process.

32

We expect a final decision on Class VI UIC permits for our CTV I A1-A2 CO2 storage reservoir at Elk Hills and our Class VI permits for CTV II (Union Island) and CTV III (Victoria Island) in 2026. We cannot provide assurances as to the actual timing of EPA’s approval of the Class VI UIC permits, or that those permits will not be challenged, and cannot guarantee how these matters could ultimately delay or otherwise adversely impact our ability to timely execute our CCS projects.

Federal Tax Credits

The Inflation Reduction Act enhanced existing credits for the capture and sequestration of carbon dioxide (45Q credit) by increasing the size of the maximum credit to $85 per metric ton of qualified carbon dioxide when such carbon dioxide is captured from industrial and power generation facilities and to $180 per metric ton of carbon dioxide when a direct air capture facility is utilized to capture such carbon dioxide, and, in each case, when such captured carbon dioxide is disposed of by the taxpayer in secure geological storage. The Inflation Reduction Act also extended the date for when qualifying facilities must begin construction to before January 1, 2033. Further, a direct pay option for the 45Q credit (for a limited five-year period) was added for new projects placed in service after December 31, 2022, and the Inflation Reduction Act provides an option to monetize the 45Q credit through a sale of the 45Q credit to an unrelated taxpayer for tax years beginning after December 31, 2022. These additional energy-related tax incentives enhance the economics for development of CCS projects in California. The accessibility of direct pay, tax equity financing, and the credit transfers market for 45Q credits provided under the Inflation Reduction Act is still developing, and therefore uncertainties and complexities with respect to our (or our partners) ability to efficiently monetize the 45Q credit exist. The One Big Beautiful Bill Act enacted on July 4, 2025, amended section 45Q to restrict certain ownership and debt sources from specified foreign entities.

The current administration recently signed several Executive Orders reversing, revoking or rescinding many climate-related actions and has expressed a desire to make modifications to the Inflation Reduction Act. The enactment of any legislation that reduces or eliminates 45Q credits could have an adverse effect on the development of our carbon management business and its prospects. For more information, see Part 1, Item IA – Risk Factors – Risks Related to Carbon TerraVault and Our Carbon Management Segment, Our Carbon TerraVault business and other CCS projects depend on financial and tax incentives to be economical, and these incentives may not currently be sufficient for our Carbon TerraVault business and other CCS projects to be economical, may not be fully realized, or could be changed or terminated.

Regulation of Climate Change and Greenhouse Gas (GHG) Emissions

A number of international, federal, state, regional and local efforts seek to prevent or mitigate the effects of climate change or to track, mitigate and reduce GHG emissions associated with energy use and industrial activity, including operations of the oil and natural gas production sector and those who use our products as a source of energy or feedstocks. While in office, President Biden issued several executive orders on climate change. However, upon the first days in office, the current administration signed several Executive Orders reversing, revoking or rescinding many climate-related actions and it remains to be seen how such Executive Orders may impact our business and what may result from any litigation, administrative or legislative actions relating to such Executive Orders.

Separately, California has adopted stringent laws and regulations to reduce GHG emissions and may continue to adopt more. The current state laws and regulations:

•established a “cap-and-invest” program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually through 2045 (the year that the state’s “cap-and-trade" program currently expires);

•require allowances or qualifying offsets for GHGs emitted from California operations and for the volume of natural gas, propane and liquid transportation fuels sold for use in California;

•established a low carbon fuel standard (LCFS) and associated tradable credits that require a progressively lower carbon intensity of the state's fuel supply than baseline gasoline and diesel fuels, and provide a mechanism to generate LCFS credits through innovative crude oil production methods such as those employing solar or wind energy or carbon capture and sequestration;

33

•mandated that California derive 60% of its electricity for retail customers from renewable resources by 2030;

•established a policy to derive all of California’s retail electricity from renewable or "zero-carbon" resources by 2045, subject to required evaluation of the feasibility by state agencies;

•imposed state goals to double the energy efficiency of buildings by 2030 and to reduce emissions of methane and fluorocarbon gases by 40% and black carbon by 50% below 2013 levels by 2030; and

•mandated that all new single family and low–rise multifamily housing construction in California include rooftop solar systems or direct connection to a state–approved community solar system.

In November 2024, CARB finalized amendments to the LCFS Regulation which included increasing 2030 carbon intensity (CI) targets from 20% to 30% and extending CI reductions to 90% by 2045. Additional updates include additional funding of zero-emission vehicle charging and hydrogen fueling infrastructure, amongst other matters. The final rulemaking package was enacted in June 2025.

California's cap-and-invest program is a market-based emissions reduction program to limit GHG emissions. AB 1207, further discussed above, extends the cap-and-invest program through 2045. The program applies to major GHG-emitting sources such as electricity generation and industrial facilities, with set carbon benchmarks that gradually decrease each year. Covered emitters must either reduce their emissions below this benchmark or purchase allowances at auction, incentivizing investment in lower-emissions technologies. However, unlike the LCFS, CARB’s CCS protocol has not yet been incorporated into the cap-and-invest program. The timing for the adoption of a protocol is unclear. Until CARB adopts a CCS protocol for cap-and-invest, the program does not have a mechanism for GHG emissions sequestered using CCS to be incorporated into the program and may be treated no different than unabated emissions. If CARB fails to adopt a CCS protocol for cap-and-invest, this could result in certain projects becoming less or non-economical, which in turn could limit our ability to successfully pursue certain CCS projects in the future. We are exploring alternative approaches to account for carbon capture under the California cap-and-invest program, but we cannot guarantee that CARB will accept these alternative approaches or that we will be able to pursue them in a timely manner to support our carbon capture projects.

In addition, the current Governor of California and certain municipalities in California have announced their commitment to adhere to GHG reductions called for in the Paris Agreement through executive orders, pledges, resolutions and memoranda of understanding or other agreements with various other countries, U.S. states, Canadian provinces and municipalities. In furtherance of this commitment, in September 2022, the Governor of California signed Assembly Bill No. 1279 into law, which codifies a previously issued executive order by the Governor's Office requiring the state to achieve carbon neutrality by 2045. In addition, the Governor of California previously issued an executive order directing several agencies to take further actions with respect to reducing emissions of GHGs. The Governor has also directed state agencies to implement other measures to mitigate climate change and strengthen biodiversity, such as via the conservation of 30% of state lands and waters by 2030. For more information, see Part I, Item 1A – Risk Factors, Risks Related to Regulation and Government Action, Recent and future actions by the State of California could reduce both the demand for and supply of oil and natural gas within the state and consequently have a material adverse effect on our business, and financial condition and results of operations.

The EPA and the CARB have also expanded direct regulation of methane as a contributor to GHG emissions. For example, in December 2023, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources, known as OOOOc. However, the rule is currently being challenged and, in December 2025, the EPA finalized a rule extending various compliance deadlines pursuant to OOOOb and OOOOc. Additionally, following the change in administration, further proposals have been made to repeal or otherwise modify these requirements, including the EPA’s GHG “Endangerment Finding,” which underpins the majority of EPA’s GHG regulations. We cannot predict whether such efforts will ultimately be successful.

Regulation of Transportation, Marketing and Sale of Our Products

Our sales prices of oil, NGLs and natural gas in the U.S. are set by the market and are not presently regulated.

34

Federal and state laws regulate transportation rates for, and marketing and sale of, petroleum products and electricity with respect to certain of our operations and those of certain of our customers, suppliers and counterparties. Such regulations also govern:

•interstate and intrastate pipeline transportation rates for oil, natural gas and NGLs in regulated pipeline systems;

•prevention of market manipulation in the oil, natural gas, NGL and power markets;

•market transparency rules with respect to natural gas and power markets;

•the physical and futures energy commodities market, including financial derivative and hedging activity; and

•prevention of discrimination in natural gas gathering operations in favor of producers or sources of supply.

The federal and state agencies overseeing these regulations have substantial rate-setting and enforcement authority, and violation of the foregoing regulations could expose us to litigation with government authorities, counterparties, special interest groups and others.

International treaties and regulations also affect the marketing or sale of our products. In addition, mandates or subsidies have been adopted or proposed by the state and certain local governments to require or promote renewable energy or electrification of transportation, appliances and equipment, or prohibit or restrict the use of petroleum products, by our customers or the public.

Available Information

We make available, free of charge on our website www.crc.com, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Definitive Proxy Statements and amendments to those reports filed or furnished, if any, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Unless otherwise provided herein, information contained on our website is not part of this report. The SEC maintains an internet site, http://www.sec.gov, that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

In addition to its reports filed or furnished with the SEC, the Company publicly discloses material information from time to time in its press releases, at annual meetings of Shareholders, in publicly accessible conferences and investor presentations, and through its website (principally in its Investor Relations page). References to the Company's website in this Form 10-K are provided as a convenience and do not constitute, and should not be deemed, an incorporation by reference of the information contained on, or available through, the website, and such information should not be considered part of this Form 10-K.