California Resources Corp

We are an independent energy and carbon management company committed to energy transition. We are committed to environmental stewardship while safely providing local, responsibly sourced energy. We are also focused on maximizing the value of our land, mineral ownership, and energy expertise for decarbonization by developing carbon capture and storage (CCS) and other emissions-reducing projects.

Our principal business consists of two segments: oil and natural gas and carbon management. The oil and natural gas segment explores for, develops and produces crude oil, oil condensate, natural gas liquids and natural gas. The carbon management segment, which we refer to as Carbon TerraVault, is expected to build, install, operate and maintain CO 2 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 Operationsand Results of our Carbon Management Segment, and Part II, Item 8 – Financial Statements and Supplementary Data, Note 16 Segment Information.

On July 1, 2024, we obtained by way of merger all of the ownership interests in Aera. The Aera Merger added significant oil-weighted production and proved developed reserves to CRC, primarily in the San Joaquin and Ventura basins. In connection with the closing of the Aera Merger, we issued 21,315,707 shares of common stock to the former Aera owners (Sellers) and expect to issue additional shares during 2025 in connection with post-closing settlement. As of July 1, 2024, and immediately following the closing of the Aera Merger, our existing stockholders prior to the Aera Merger owned 76% of CRC and the Sellers owned 24% of CRC. We also paid approximately $990 million in connection with the extinguishment of all of Aera's outstanding indebtedness. For more information on the Aera Merger, refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Aera Merger.

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.

Business Strategy

•Focus on integration and synergy capture of the Aera assets to enable future consolidation opportunities. We are focused on reducing costs and improving operating efficiencies as a result of the Aera Merger. In 2024, we implemented synergies that we expect will result in future annual cost savings of $170 million, and we expect to implement additional synergies in 2025 that will result in a further $65 million in such cost savings. As the largest producer in California, we believe that we will have the opportunity to acquire additional producing assets in California at attractive valuations and we expect to pursue other acquisitions within or outside of California.

•Maintain high standards of operational performance to drive profitability and create reliable cash flows. For the year ended December 31, 2024, we generated $376 million in net income including the results of Aera's operations for the second half of the year. We intend to maintain high standards for safe and environmentally responsible operations, while also seeking to drive further efficiencies in our business through innovation and lowering costs and enhance cash flows in different commodity price environments and industry cycles.

•Maintain a disciplined and flexible capital program. We expect to allocate capital among assets based on permit availability and manage field-level development. Over the short term, we intend to primarily invest in workovers and sidetracks to take advantage of permit availability. When permitting for new wells resumes, we plan to invest in developing wells with high returns and short payback metrics. We expect to fund our capital program primarily from operating cash flows and maintain a flexible approach to adapt to fluctuations in commodity prices and changes in the regulatory climate.

•Preserve balance sheet strength and shareholder returns. As of December 31, 2024, we had $1,337 million of liquidity, consisting of $983 million available for borrowing under the Revolving Credit Facility (after taking into account $167 million of outstanding letters of credit) and $354 million in cash on hand. We had $1,145 million of long term indebtedness as of the same date. By maintaining significant liquidity and low leverage, we believe we will be able to ensure a strong financial foundation that will allow us to focus on shareholder returns, including dividends and share repurchases.

•Advance our carbon management business to lead the energy transition. We are focused on maximizing the value of our land, mineral and technical resources for decarbonization by developing CCS and other emissions reducing projects. We expect to deliver industrial-scale projects to help California meet its decarbonization goals. We intend to leverage our Carbon TerraVault JV with Brookfield to reduce our capital investments to develop these projects. We are also focused on maximizing opportunities and optimizing long term value for our existing natural gas fired power generation assets, including our 550 MW power plant at Elk Hills.

•Proactively and collaboratively engage in matters related to regulation and HSE matters. We seek to work with regulators and legislators at the state and local levels in an effort to minimize potential adverse impacts that new legislation and regulations may have on our business and operations. Our commitment to health, safety and the environment (HSE) defines how we operate our business. We intend to always produce energy in a safe and responsible manner to help support and enhance the quality of life in the communities in which we operate.

•Maintain our commitment to environmental stewardship. We intend to continue efforts to reduce CO 2 and methane emissions in our operations. We also intend to continue to proactively manage our idle wells and reduce our consumption of freshwater in our operations. We are committed to transparency in these efforts and intend to continue to disclose our progress regularly, including through our annual sustainability report. We expect to continue to seek third party certifications of our results and disclosure practices, such as MIQ’s certification of methane emissions.

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, 2024:

(a)We reduced the number of producing fields reported in 2023 by removing certain fields that were classified as abandoned, shut-in or non-producing. This change has no impact on our production volumes.

(b)2 MBoe/d of production in the Salinas Basin for the year ended December 31, 2024 is included in Other Basins. Salinas Basin production was included in the San Joaquin Basin in prior periods.

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.

San Joaquin Basin

Commercial petroleum development in the San Joaquin basin began in the 1800s. The basin 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.

We have interests in oil and gas fields throughout the San Joaquin basin, including in Elk Hills, Buena Vista, Coles Levee, North Belridge and South Belridge, Kern Front, Lost Hills, Cymric, McKittrick, Midway Sunset and Coalinga.

We hold substantially all of the working and mineral interests in the Belridge field. We operate the Belridge field, which consists of the North Belridge and South Belridge fields. The Belridge field consists of waterflood and steamflood operations. In the steamfloods 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.

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

We believe our extensive 3D seismic library, which covers over 800,000 acres in the San Joaquin basin, or over 50% 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. 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) under which we first recover the capital and operating costs we incur on behalf of the state and the city of Long Beach and then receive our share of profits. See Production, Price and Cost History below for more information on our PSCs.

Sacramento Basin

The 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.

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, 2024.

(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, 2024, 79% of our total net mineral interest position was held in fee and the remainder was leased. Of our leased acreage, approximately 85% 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 leasing that acreage. 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 9,000 net mineral acres will expire in 2025, 6,000 net mineral acres will expire in 2026 and 7,000 net mineral acres will expire in 2027. These leases represent 2% of our total net undeveloped acreage and 1% of our total net acreage as of December 31, 2024 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.

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 Operationsfor more information on our production activity as well as the impact of price increases of certain commodities used in our operations and on our operating costs per Boe, among other factors.

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

Oil, natural gas and NGL production for our two largest fields for the years ended December 31, 2023 and 2022 are 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.

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to PSCs that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of production and reserves to recover a portion of such capital and operating costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and operating costs that we incur on their behalf, (ii) for our share of contractually defined base production, 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 12% of our total production for the year ended December 31, 2024.

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 related to our exploration and production activities and are presented before elimination entries beginning in 2024.

(b)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.

The following table reconciles our average net production to our average gross production (which includes production from the fields we operate and our share of production from fields operated by others) for the periods presented:

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, 2024. 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 $80.42 per barrel was adjusted for gravity, quality and transportation costs. For natural gas volumes, the average NYMEX gas price of $2.13 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, 2024 were $77.91 per barrel for oil, $46.73 per barrel for NGLs and $2.71 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 Informationfor additional information on our proved reserves.

(a)As of December 31, 2024, approximately 8% of proved developed oil reserves, 7% of proved developed NGLs reserves, 9% of proved developed natural gas reserves and, overall, 8% 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.

(b)Calculated as total proved reserves as of December 31, 2024 divided by total production for the year ended December 31, 2024.

Changes to Proved Reserves

The components of the changes to our proved reserves during the year ended December 31, 2024 were as follows:

(a)Includes proved reserves related to PSCs of 62 MMBoe and 76 MMBoe at December 31, 2024 and 2023, respectively.

Revisions related to price– We had net negative price-related revisions of 15 MMBoe primarily resulting from lower average realized prices in 2024 as compared to 2023, including lower natural gas realizations in 2024. These revisions included negative price-related revisions of 18 MMBoe, which were partially offset by 3 MMBoe of positive revisions from operating cost efficiencies.

Revisions related to performance– We had 2 MMBoe of net positive performance-related revisions which included positive performance-related revisions of 12 MMBoe and negative performance-related revisions of 10 MMBoe. Our positive performance-related revisions primarily related to better-than-expected well performance. Our negative performance-related revisions primarily were due to lower overall expected recovery in the San Joaquin basin.

Revisions due to California regulatory challenges – We had 7 MMBoe of negative revisions due to lower maximum allowable surface injection pressure at the Wilmington field in the Los Angeles basin. We had 1 MMBoe of negative revisions due to the impact of AB 2716 at the Inglewood field in the Los Angeles basin. We had 2 MMBoe of negative revisions due to the retraction of the SB 1137 referendum and our analysis of sensitive receptor designations. The majority of these revisions were located in the Los Angeles Basin. We had 6 MMBoe of negative revisions associated with delays in obtaining new well drilling permits. The majority of the revisions related to permits was in the San Joaquin basin. See Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities.

Acquisitions – We acquired 236 MMBoe in the Aera Merger. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Aera Mergerfor more information on this transaction.

Proved Undeveloped Reserves

The total changes to our proved undeveloped reserves during the year ended December 31, 2024 were as follows:

Revisions related to price– We had 3 MMBoe of net negative price-related revisions primarily resulting from lower average realized prices in 2024 as compared to 2023, including lower natural gas realizations in 2024. Our negative price revisions of 3 MMBoe were partially offset by insignificant positive revisions from operating cost efficiencies.

Revisions related to performance– We had 5 MMBoe of net negative performance-related revisions due to low performance of recent drilling and subsequent type curve updates in the San Joaquin basin. Negative performance-revisions of 5 MMBoe were partially offset by insignificant positive revisions related to well performance in the San Joaquin basin.

Revisions due to California regulatory challenges – We removed 10 MMBoe from proved undeveloped reserves due to the regulatory changes discussed above. The majority of these revisions were located in the San Joaquin basin and the Los Angeles basin. See Regulation of the Industries in Which We Operate, Regulations of Exploration and Production Activities.

Acquisitions – We acquired 12 MMBoe in the Aera Merger. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Aera Mergerfor more information on this transaction.

Transfers to proved developed reserves– We converted 2 MMBoe of proved undeveloped reserves to proved developed reserves in the Los Angeles basin. This resulted in a conversion rate of 4% of our beginning-of-year proved undeveloped reserves, with an investment of $44 million in drilling and completion capital. We plan to continue drilling sidetracks in 2025 and, subject to the availability of permits, expect to increase our rig count in the second half of the year. We believe that we will be able to develop all year-end 2024 proved undeveloped reserves within five years of their original booking date. For more information on the 2025 Capital Program, see Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Uses of Cash and for more information on permitting, refer to Regulation of the Industries in Which We Operate, Regulations of Exploration and Production Activities.

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 measures 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.

(a)The average realized prices for estimating our PV-10 of cash flow as of December 31, 2024 were $77.91 per barrel for oil, $46.73 per barrel for NGLs and $2.71 per Mcf for natural gas.

Reserves Evaluation and Review Process

Our estimates of proved reserves and related discounted future net cash flows as of December 31, 2024 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 15 years of experience in the upstream oil and gas industry, with projects ranging from appraisal of primary production reservoirs to enhanced oil recovery floods. 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 2024. The Reserves Committee annually reports its findings to the Audit Committee.

Audits of Reserves Estimates

Netherland, Sewell & Associates, Inc. (NSAI) was engaged to provide independent audits of our reserves estimates for our fields. For the year ended December 31, 2024, NSAI audited 85% of our total proved reserves.

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.

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 issued an unqualified audit opinion on the applicable portions of our proved reserves as of December 31, 2024, which is attached as Exhibit 99.1 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 5 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 11 years of prior industry experience.

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 2025 capital program, see Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Uses of Cashand 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 development wells where drilling was either in progress or pending completion as of December 31, 2024.

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 97% as of December 31, 2024. Wells are categorized based on the primary product they produce.

The following table sets forth our productive oil and natural gas wells (both producing and capable of production) as of December 31, 2024, 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 have had minimal investment in exploration activity in recent years, and our 2025 capital plan does not allocate any capital towards exploration drilling.

Marketing Arrangements

Our oil, natural gas and NGL sales for the years ended December 31, 2024, 2023 and 2022 are shown in the table below. For more information on our revenues, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 15 Revenue.

Crude Oil

We sell nearly all of our crude oil to California refiners. A majority of our crude oil production is connected to third-party pipelines and California refining markets via our gathering systems. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.

The prices paid by California refiners have been typically based on local postings that are closely tied to Brent prices. Beginning in 2025, the marketing arrangements for the majority of our production will no longer rely on local postings but will instead be 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.

In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025. For the six-month period following the Aera Merger, we sold approximately 8% of our production to this refinery. Following the closure of the Phillips 66 refinery, there will be seven remaining major petroleum refineries in California, each of which have a refining capacity greater than 75,000 barrels per day. Due to the significant excess of refining capacity in California versus the quantity of crude oil produced locally, we do not expect the closure of this refinery to affect our ability to market our crude oil production, or to negatively impact our price realizations.

Natural Gas

We sell all of our natural gas not used in our operations into the California market. A majority of these sales are made at index based prices. Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity between the market and producing areas. Transportation capacity influences prices because California imports more than 90% of its natural gas from other states and Canada.

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 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 ship-or-pay pipeline transportation contract for 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 have met all our throughput minimums under this contract for the periods presented.

Delivery Commitments

We have commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs, including delivery commitments obtained as part of the Aera Merger. As of December 31, 2024, we had the following delivery commitments as shown in the table below.

We expect to fulfill our delivery commitments predominantly from our production 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 sell crude oil, natural gas and NGLs to California refineries, marketers and other purchasers that have access to transportation and storage facilities. 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 Otherfor more information on our customers.

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.

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 approximately 75% of the oil it consumes and approximately 90% 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 the unique characteristics which are similar to our produced oil. The California natural gas market is serviced from a network of pipelines, including interstate and intrastate pipelines. We deliver our natural gas to customers using our firm capacity contracts.

We compete for third-party services 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. However, we have not experienced shortages or delays in the delivery of materials or services from our vendors.

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 CO 2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO 2 deep underground. We also expect to invest in projects that rely on CCS technology in connection with reducing our own emissions. In addition, we may participate in the development of projects that are the source of these CO 2 emissions.

EPA Class VI Permits

We are in the early stages of developing several CCS projects in California. In December 2024, the EPA issued Class VI permits, the first permits issued in California, for underground injection and storage of CO 2 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 joint venture with Brookfield 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 one permanent sequestration project 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. Our permit applications are subject to additional review and approval by the EPA.

CCS Projects

In January 2025, we announced the approval of the installation of carbon capture equipment at our cryogenic gas processing facility at the Elk Hills field which will remove CO 2 from inlet gas and which will be injected into the nearby 26R storage reservoir owned by the Carbon TerraVault JV. We expect this project will increase operational efficiency of the cryogenic gas processing plant, improving propane recovery, and reduce the carbon intensity of the electricity generated from our Elk Hills Power Plant. Our expected capital investment for this project is $14 million to $18 million with operations expected to commence in late 2025. We are also evaluating the feasibility of developing a carbon capture system for our 550-megawatt Elk Hills power plant (CalCapture). We continue to work with a consortium of industry participants to advance the development of a direct air capture hub to be located in Kern County and have been selected for a U.S. Department of Energy grant for this project as discussed further below.

We expect that the size and scope of our projects providing these and similar services and the related capital spent on such projects will continue to grow given our strategy of expansion into these services and the development of our carbon management segment. 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 CO 2 into the 26R reservoir in our Elk Hills field for permanent CO 2 storage. Brookfield has contributed $92 million to date. The remaining amount of Brookfield's initial investment will depend on the amount of storage capacity that is permitted subject to certain contractual adjustments. The parties have certain put and call rights with respect to the 26R reservoir if certain milestones are not met. As noted above, on December 30, 2024, the EPA issued Class VI permits to the Carbon TerraVault JV for the CTV I storage site.

Both Brookfield and CRC have granted the other party a right to participate in projects that involve the capture, transportation and storage of CO 2 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.

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

In our carbon management segment, we compete with other potential storage providers to acquire and develop storage reservoirs and enter into agreements with existing and future emission sources.

Infrastructure

Our infrastructure includes the plants and facilities shown in the table below, inclusive of our assets used in power generation and oil and natural gas operations.

(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 Plants

We own and/or operate the following power generation facilities:

Elk Hills Power Plant – We own a 550 MW combined-cycle cogeneration power plant, located adjacent to the Elk Hills natural gas processing facility. Approximately a third of the electricity generated from this plant is used in our oil and natural gas operations at Elk Hills. The balance of the power capacity is currently marketed into the resource adequacy market with excess energy produced being sold into the CAISO wholesale market.

Midway Sunset Power Plant – Following the Aera Merger, we own a 50% interest in a 240 MW cogeneration power plant located in the Midway Sunset field in Kern County, California 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.

Belridge Power Plant – Following the Aera Merger, 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.

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 Used in Oil and Natural Gas Segment

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 operations in the San Joaquin basin and supports our high-margin oil fields. 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.

Human Capital Management

We had approximately 1,550 employees as of December 31, 2024 as compared to approximately 970 as of December 31, 2023, all of whom were located in the United States. The significant growth in headcount was due to the employees who joined CRC following the Aera Merger. Approximately 240 of our employees are covered by a collective bargaining agreement. We also utilize the services of many third-party contractors throughout our operations.

Development

Employee development opportunities are provided to enhance leadership development 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. All employees receive annual performance reviews.

Diversity

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

Safety

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 spill prevention as quantitative metrics that directly impact incentive compensation for all of our employees. We achieved a 99.999% oil spill prevention rate in 2024 and registered a workforce TRIR of 0.39 (including Aera's results following the Aera Merger). 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.

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. The State Lands Commission provides additional administration of the state’s surface and mineral interests.

Regulation of Exploration and Production Activities

Well Permitting

During 2024, we continued to experience delays from CalGEM with respect to obtaining new well, sidetrack, deepening and workover permits for our operations. These delays are a result of various factors, including more stringent environmental reviews in connection with permitting, limited resources at CalGEM, and policy directives that are outside of our control.

During 2024, we (including our Aera subsidiary) received well permits for 799 workovers and 145 sidetracks.

New Production Permits

Since December 2022, CalGEM has issued a limited number of permits to other operators for new production wells in California. In 2024, CalGEM issued 77 new well permits to other operators, 40 of which were for oil and natural gas production wells and 37 of which were for injection and observation wells. These permits were issued for wells outside of Kern County or within Kern County but in reliance on authority other than the Kern County EIR discussed below.

We continue to pursue an alternative path for the permitting of wells in Kern County other than in reliance on the Kern County EIR. We have submitted applications for conditional use permits (CUPs) for projects at our Aera subsidiary's Belridge field and our Kern Front, Elk Hills and Buena Vista fields. Timing for completion of the CUP application processes is difficult to estimate and could extend into the first half of 2026. Our ability to obtain the CUPs is uncertain and we may not be successful in obtaining such permits in a timely manner or at all.

Sidetrack, Deepening and Workover Permits

CalGEM finalized its procedures for the review of permit applications for workovers in December 2023 and its lead agency review process for sidetrack permits in September 2024 and recently resumed evaluation of permits for deepenings. Following the adoption of these procedures, we experienced an increase in the issuance by CalGEM of permits for workovers and sidetracks during the course of 2024. However, the rate of issuance of permits for deepening wells has not increased.

We cannot guarantee that the issues described above or new ones that may arise in the future will not continue to delay or otherwise impair our ability to obtain drilling permits. Any continuing failure to obtain certain permits or the adoption of more stringent permitting requirements could have a material adverse effect on our business, results of operations and our financial condition. See Part 1, Item IA – Risk Factors, 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

In 2015 the Kern County Board of Supervisors (i) approved the county’s adoption of an ordinance providing for a single proscribed project for the development of oil and natural gas wells in the county by the various operators within their individual fields; and (ii) certified the Environmental Impact Report (EIR) prepared by the county for the project. Following the adoption of the ordinance, the county relied on the certified EIR to satisfy CEQA requirements for the well permits issued under the ordinance.

Our operations in Kern County have been subject to significant uncertainty over the past several years as a result of ongoing challenges to Kern County’s ability to rely on the EIR and its subsequent iterations to satisfy CEQA requirements for well permits issued under the ordinance. In December 2015, several groups filed CEQA litigation against Kern County challenging the EIR. These proceedings have resulted in multiple rulings and appeals and the matter remains ongoing. The Trial Court imposed a stay on the issuance of new well permits under the ordinance in June 2022 which has remained in effect throughout most of the litigation and is currently in effect pending resolution of the matter by the Court of Appeals.

On March 7, 2024, the Court of Appeals issued its ruling on challenges made to a revised EIR. As a result, Kern County was directed to (a) prepare a further revised EIR that corrects deficiencies relating to (1) the rejection of agricultural conservation easements as a form of partial mitigation for the conversion of agricultural land, (2) assessment of cancer risks associated with the drilling of multiple wells near sensitive receptors and (3) analysis of water supply impacts; and (b) circulate the further revised EIR for public review and comment, and subsequently certify this revised EIR.

On March 22, 2024, Kern County released a notice of preparation of the further revised EIR. Kern County is expected to circulate a draft for public comment in the first quarter of 2025 and thereafter seek the Trial Court’s determination on this EIR’s compliance with the ruling of the Court of Appeals, certify this EIR and approve the revised ordinance. After that, the Trial Court would then be able to lift the stay, subject to further potential appeals. If the stay is lifted, new well permitting could resume. However, there is no certainty we will obtain permits on that timeline or at all, or that the Trial Court will approve the certification of the further revised EIR or lift the stay, which could further adversely affect our business, results of operations and financial condition.

As a result of these issues and current lack of permits with respect to our Kern County properties, we plan to operate one active drilling rig within Kern County in the first half of 2025 and have the requisite number of permits in hand to keep that rig active through the end of 2026. We operated one rig in 2024. We plan to begin drilling certain sidetracks under existing sidetrack permits in the first half of 2025 and plan to increase our active rig count in Kern County to two (2) rigs in the second half of 2025. In 2025, approximately $21 million of capital to develop proved reserves relates to drilling and completing sidetracks in Kern County for which we do not presently have a permit. If we are unable to obtain the necessary permits for the development of these wells, we will pursue alternatives for the deployment of this capital. For more information on our 2025 Capital Program, see Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Uses of Cash.

Regulatory Activity

The California Legislature and Governor have significantly increased the jurisdiction, duties and enforcement authority of CalGEM, the State Lands Commission and other state agencies with respect to oil and natural gas activities in recent years through legislation and policy pronouncements. CalGEM’s duties now include public health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s energy needs. CalGEM is also required to study and prioritize idle wells with emissions, evaluate costs of abandonment, decommissioning and restoration, and review and update associated indemnity bond amounts from operators if warranted, up to a specified cap which may be shared among operators. 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 limiting well stimulation, completion or injection activities, imposing setback distances from certain other land uses, or banning such activities outright. Other local governments have also sought to ban natural gas or the transportation of natural gas through their cities. For example, the cities of Brentwood and Antioch have refused to extend the necessary franchise agreements to preserve an existing pipeline that runs through their jurisdictions. In July 2023, one of our subsidiaries submitted an application with the CPUC to convert this pipeline to common carrier status. The application is still pending.

Setbacks and Senate Bill 1137 (SB 1137)

On September 16, 2022, the Governor of California signed Senate Bill No. 1137 which established 3,200 feet as the minimum distance between new oil and natural gas production wells and certain sensitive receptors such as homes, schools and businesses open to the public and separately imposed a number of potential impact analysis and mitigation and reporting requirements. Senate Bill No. 1137 was stayed during a referendum process that was ultimately withdrawn and finally became effective on June 27, 2024. However, on September 30, 2024, the Governor signed into law Assembly Bill No. 218, which extends the timeline for the implementation of certain initial and future monitoring and reporting requirements until July 1, 2026 and further delays compliance with certain other requirements by up to three years. Assembly Bill. No. 218 does not modify the 3,200-foot setback requirements applicable to new wells, sidetracks, deepenings or workovers.

The majority of our production is in rural areas in the San Joaquin basin and is not affected by Senate Bill No. 1137. In addition to the write-down of reserves previously recorded in 2023, we continue to evaluate the location of projects near setback zones and believe any further reductions to the net present value of our proved undeveloped reserves as a result of the implementation of Senate Bill No. 1137 would be immaterial.

Idle Wells and Assembly Bill 1866 (AB 1866)

This law, effective January 1, 2025, increases the annual fees operators must pay per idle well, depending on how long each well has been idle, and includes a new fee for those wells that have been idle for less than three years. In lieu of the annual fees, operators can instead file an eight-year plan with the State to provide for the management and elimination of their idle wells. This law also increases the minimum percentages of idle wells that operators are required to eliminate each year. The rate at which idle wells must be eliminated varies depending on the number of an operator’s idle wells. Operators must prepare and submit a plan for the elimination of idle wells to CalGEM for approval. We implement robust programs for managing and eliminating idle wells that meet or exceed the requirements of the new law. As a result, we do not expect this new law to have any meaningful impact on our current plans for eliminating idle wells or meaningfully increase fees associated with our idle wells.

Baldwin Hills Conservancy and Assembly Bill 2716 (AB 2716)

This law requires operators to plug “low production wells” located within the boundary of the Baldwin Hills Conservancy in Los Angeles within a certain timeframe or otherwise subjects operators to administrative penalties. A “low-production well” is a well that produced fewer than an average of 15 barrels of oil a day during the past 12 months. We have limited operations and assets within the affected area. As a result, we expect that this law will not have a material adverse effect on either our total production or proved reserves.

Local Regulation and Assembly Bill 3233 (AB 3233)

This law provides local governments with the authority to limit methods for, or even prohibit oil and gas operations or development within their jurisdiction, including with respect to existing operations. Prior to the passage of this law, certain local governments in California, including the City and County of Los Angeles and Monterey County, had attempted to limit oil and gas operations within their jurisdictions and such actions had been challenged and struck down by California courts. However, following the adoption of AB 3233, certain legal challenges previously made to these local actions are no longer valid and it is possible that these or other local governments in California may attempt to pass new or similar restrictions. Future bans or restrictions on production or development by the City of Los Angeles or the counties of Los Angeles and Monterey could impact our production negatively or result in the write-down of our reserves.

For the fiscal year ended December 31, 2024, over 70% of our gross production is located in Kern County, and at this time we are not aware of any local governments within Kern County that are considering materially limiting or otherwise prohibiting oil and gas operations within their jurisdiction. However, it is difficult to predict how local governments in California may choose to exercise their new authority under AB 3233. There may be future legal challenges to AB 3233 and any local ordinances enacted thereunder and we cannot predict whether or not such challenges will be successful.

See Part 1, Item IA – Risk Factors –We may face increased local restrictions on oil and gas exploration and production operations or even be prohibited from operating in certain areas as a result of recently enacted California legislation.

Bonding and Assembly Bill 1167 (AB 1167)

On October 7, 2023, the California Governor signed into law Assembly Bill 1167 (AB 1167), which imposes more stringent financial assurance requirements on persons who acquire the right to operate a well or production facility in California, requiring them to file either an individual indemnity bond for single-well or production facility acquisitions, or a blanket indemnity bond for multiple wells or production facilities. Upon signing AB 1167, Governor Newsom called for further legislative changes to these new requirements to mitigate against the potential risk of the implementation of AB 1167 ultimately increasing the number of orphaned idle or low-producing wells in California, although no such changes have yet been announced. We cannot predict what form these changes may ultimately take or if the legislature will act on the Governor’s request. Implementation of this law may lead to the delay or additional costs with respect to certain acquisitions or dispositions, which could impact our ability to grow or explore new strategic areas – or exit others – within California.

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 proposed draft of a final rule that would enhance requirements for detecting and repairing leaks on new and existing natural gas distribution, gas transmission and gas gathering pipelines. 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. PHMSA finalized this proposed rule in January 2025.

Water Injection

Our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. During 2024, we entered into discussions with the City of Long Beach and CalGEM regarding the level of injection well pressure gradient needed to comply with CalGEM’s requirements for the protection of underground aquifers, while at the same time mitigating subsidence risks. In July 2024, CalGEM issued a directive to reduce the injection well pressure in a gradual manner and we implemented a five-year injection reduction work plan. The first phase of reduction commenced July 1, 2024 with a second reduction beginning in January 2025. We continue to evaluate the work plan with CalGEM, including any subsidence risk, and the work plan may be adjusted further in the future. Given this uncertainty, it is difficult to predict with accuracy the impact to production and reserves. However, assuming no adjustments to the current work plan, we estimate a negative impact on production of approximately 1 MBoe/d at the end of the 5-year work plan. We also estimate that the net present value of our proved developed reserves would be negatively impacted by less than 1%. These estimates could change materially pending the results of future technical audits.

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, we were recently named a real party in interest in Center for Biological Diversity v. City of Long Beach, Long Beach City Council, California State Lands Commission, et al., a lawsuit brought by an environmental non-governmental organization seeking various remedies on the basis of a purported failure to conduct a CEQA review. In January 2025, the Superior Court of California, County of Los Angeles, denied the claimant’s petitions. Following this decision, we do not expect a material adverse effect on our business or operations as a result of this lawsuit, pending the outcome of any appeals.

Separately, 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.

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, Pipeline Safety Improvement Act, Pipeline Safety, Regulatory Certainty, and Job Creation Act, Endangered Species Act, Migratory Bird Treaty Act, Comprehensive Environmental Response, Compensation, and Liability Act, Resource Conservation and Recovery Act and NEPA, among others. California imposes additional laws that are analogous to, and often more stringent than, such federal laws. These laws and regulations:

•establish air, soil and water quality standards for a given region, such as the San Joaquin Valley, conduct regional, community or field monitoring of air, soil or water quality, and require attainment plans to meet those regional standards, which may include significant mitigation measures or restrictions on development, economic activity and transportation in such region;

•require various permits, approvals and mitigation measures before drilling, workover, production, underground fluid injection or waste disposal commences, or before facilities are constructed or put into operation;

•require the installation of sophisticated safety and pollution control equipment, such as leak detection, monitoring and shutdown systems, and implementation of inspection, monitoring and repair programs to prevent or reduce releases or discharges of regulated materials to air, land, surface water or ground water;

•restrict the use, types or sources of water, energy, land surface, habitat or other natural resources, require conservation and reclamation measures, impose energy efficiency or renewable energy standards on us or users of our products and services, and restrict the use of oil, natural gas or certain petroleum–based products such as fuels and plastics;

•restrict the types, quantities and concentrations of regulated materials, including oil, natural gas, produced water or wastes, that can be released or discharged into the environment, or any other uses of those materials resulting from drilling, production, processing, power generation, transportation or storage activities;

•limit or prohibit operations on lands lying within coastal, wilderness, wetlands, groundwater recharge, endangered species habitat and other protected areas, and require the dedication of surface acreage for habitat conservation;

•establish standards for the management of solid and hazardous wastes or the closure, abandonment, cleanup or restoration of former operations, such as plugging and abandonment of wells and decommissioning of facilities;

•impose substantial liabilities for unauthorized releases or discharges of regulated materials into the environment with respect to our current or former properties and operations and other locations where such materials generated by us or our predecessors were released or discharged;

•require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting federal, state and private lands or leases;

•impose taxes or fees with respect to the foregoing matters;

•may expose us to litigation with government authorities, counterparties, special interest groups or others; and

•may restrict our rate of oil, NGLs, natural gas and/or electricity production.

These requirements can result in restrictions on our operations. For example, in 2014, at the request of the EPA, CalGEM commenced a detailed review of the multi-decade practice of permitting underground injection wells and associated aquifer exemptions under the Safe Drinking Water Act. In 2015, the state set deadlines to obtain the EPA’s confirmation of aquifer exemptions under the Safe Drinking Water Act in certain formations in certain fields. During the review, the State has restricted injection in certain formations or wells in several fields, including some operated by us, requested that we change injection zones in certain fields, and held certain pending injection permits in abeyance. The State continues to work with EPA to resolve these issues. The aquifer exemption process has slowed in part due to the determination by CalGEM and the State Water Resources Control Board that certain of the remaining applications require additional “conduit analysis” to ensure that injected fluid will not escape from the intended area of subsurface confinement as well as EPA delays. Of the 30 original aquifer exemption proposals addressing permitted injection into a potential underground source of drinking water, 22 have been approved by EPA, with eight applications outstanding. In connection with legal challenges filed against the State by industry stakeholders, the Kern County Superior Court has issued an order generally barring the blanket enforcement of CalGEM’s aquifer exemption regulations mandating grant of an aquifer exemption as a precondition to continued injection activities.

At the federal level, recent modifications to regulations implementing NEPA may impose additional restrictions on oil and natural gas activities on federal lands. In October 2021, the Biden Administration announced three significant changes to a 2020 rule finalized under the Trump Administration. These changes included (i) authorizing agencies to consider the direct, indirect and cumulative effects of major federal actions including upstream and downstream impacts of fossil fuel projects; (ii) allowing agencies to determine the purpose and need of a project (thereby allowing consideration of less-harmful alternatives); and (iii) affording agencies greater flexibility in crafting their own NEPA procedures, consistent with Council of Environmental Quality (CEQ) regulations, so as to meet the agencies’ and public’s need. To that end, in April 2022, the CEQ issued a final rule in line with the proposed changes—“Phase I” of the Biden Administration’s two-phased approach to modifying NEPA. In May 2024—“Phase 2”—the CEQ issued a final rule revising the implementing regulations of the procedural provisions of NEPA and implementing amendments to NEPA included in the Fiscal Responsibility Act of 2023. The final rule was challenged by various states and the litigation remains ongoing. More recently, in November 2024, the U.S. Court of Appeals for the D.C. Circuit held that the CEQ lacks authority to issue NEPA regulations. Additionally, the current administration recently signed an energy-related Executive Order which included ordering the CEQ to propose rescinding its NEPA regulations. As a result, there is currently significant uncertainty with respect to the scope of environmental analysis required under NEPA.

There is also uncertainty surrounding the disbursement of federal funding. On January 20, 2025, an Executive Order was issued which paused distribution of federal funds appropriated through the Inflation Reduction Act (IRA) or the Infrastructure Investment and Jobs Act. The pause was aimed at providing time to review the processes, policies and issuance of various grants, loans, contracts or financial disbursements of appropriated funds but did not modify the IRA statutory language with respect to federal income tax credits. However, on January 29, 2025, the White House Office of Management and Budget rescinded the freezing of federal grants and loans, although not its efforts to review the processes with respect to federal spending. Although we are in receipt of small funding awards from the Department of Energy, many of our counterparts with which we are co-developing projects are dependent on much larger awards and loans. Any disruption, delay or withdrawal of federal funding could result in delays with respect to the development and timely completion of such projects or otherwise render them uneconomic, thereby adversely affecting our ability to pursue such projects.

In addition, due to the risk of future drought conditions in California, water districts and the State government have implemented regulations and policies that may restrict groundwater extraction and water usage and increase the cost of water. Water management, including our ability to recycle, reuse and dispose of produced water and our access to water supplies from third-party sources, in each case at a reasonable cost, in a timely manner and in compliance with applicable laws, regulations and permits, is an essential component of our operations to produce crude oil, natural gas and NGLs economically and in commercial quantities. As such, any limitations or restrictions on wastewater disposal or water availability could have an adverse impact on our operations. We treat and reuse water that is co-produced with oil and natural gas for a substantial portion of our needs in activities such as pressure management, waterflooding, steamflooding and well drilling, completion and stimulation. We also provide reclaimed produced water to certain agricultural water districts. We also use supplied water from various local and regional sources, particularly for power plants and steam generation. We are a net freshwater supplier to the state. While our production to date has not been impacted by restrictions on access to third-party water sources, we cannot guarantee that there may not be restrictions in the future.

Federal, state and local agencies may assert overlapping authority to regulate in these areas. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

Regulation of Carbon Capture, Sequestration and Storage

Unitization and Pipelines

On September 16, 2022, the Governor of California signed Senate Bill No. 905 into law, which 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.

Senate Bill No. 905 provides that pipelines may be used to transport carbon dioxide to or from a carbon dioxide capture, removal or sequestration project only upon conclusion of PHMSA’s rulemaking strengthening safety requirements for carbon dioxide pipelines. Although PHMSA released a notice of proposed rulemaking to this effect in early January 2025, it has not yet been published in the Federal Register and its disposition is uncertain at this time following the change in U.S. presidential administrations. Certain Carbon TerraVault projects are expected to be constructed on sites directly above underground storage facilities and would not be impacted by Senate Bill No. 905 or PHMSA’s rulemaking. For those Carbon TerraVault projects that do rely on transportation of CO 2, however, the terms of these final pipeline safety regulations may impair or prohibit our ability to timely pursue future CCS projects that rely on the transportation of CO 2.

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 a lawsuit against the County of Kern and its Board of Supervisors in Kern County Superior Court, challenging the Board of Supervisors’ certification of the EIR for non-compliance with CEQA. In addition to challenging the EIR, the Petitioners have indicated that they intend to seek injunctive relief for a stay of the project but have not yet sought such relief. At this time, we cannot predict the outcome of this litigation with certainty. Such lawsuits have the potential to delay timely construction and commencement of operations at CTV I and could otherwise have a material adverse effect on our carbon management business and its prospects.

On December 31, 2024, the EPA issued four Class VI underground injection control (UIC) permits for the construction and operation of four CO 2 injection wells at the site of the CTV I 26R underground CO 2 storage reservoir at our Elk Hills Field. Per EPA rules, the EPA opened a 30-day period during which certain persons could make limited petitions regarding the permits. No person filed a petition for review or administrative review prior to the January 30, 2025 deadline. As a result, the EPA’s permit decision became effective February 3, 2025.

We currently have 7 Class VI permit applications relating to our carbon management segment pending with the EPA in different stages of the permitting process. We expect a final decision on Class VI UIC permits for our CTV I A1-A2 underground CO 2 storage reservoir at our Elk Hills Field in the second half of 2025. We cannot guarantee the ultimate timing of EPA’s approval of the Class VI UIC permits for CTV I A1-A2 or any of our other projects, 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 oxide (45Q credit) by increasing the size of the maximum credit to $85 per metric ton of qualified carbon oxide when such carbon oxide is captured from industrial and power generation facilities and to $180 per metric ton of carbon oxide when a direct air capture facility is utilized to capture such carbon oxide, and, in each case, when such captured carbon oxide 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, and the Inflation Reduction Act provides an option to monetize the 45Q credit through a sale of the 45Q credit to another taxpayer. These additional energy-related tax incentives are effective for new projects beginning on January 1, 2023, and 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 Inflation Reduction Act also incentivizes the development of clean hydrogen production projects through the clean hydrogen production tax credit under section 45V of the Code (45V credit). The credit amount is up to $3 per kilogram multiplied by an applicable percentage for clean hydrogen for a ten-year period beginning when a qualified facility is placed in service. On January 10, 2025, the IRS and Treasury released final regulations under section 45V. The final regulations provide rules for determining lifecycle greenhouse gas emissions rates resulting from hydrogen production processes; petitioning for provisional emissions rates; verifying production and sale or use of clean hydrogen; modifying or retrofitting existing qualified clean hydrogen production facilities; using electricity from certain renewable or zero-emissions sources to produce qualified clean hydrogen; and electing to treat part of a specified clean hydrogen production facility instead as property eligible for the energy credit.

The amount of the available 45V credit from which we may directly or indirectly benefit in connection with our Carbon TerraVault business will depend on our ability to satisfy certain requirements and obtain certain emissions rate results under the most recent 45V credit Greenhouse Gasses, Regulated Emissions, and Energy Use in Transportation (45VH2-GREET) model or a petition for a provisional emissions rate. The final regulations impose certain requirements, restrictions and limitations that may eliminate or reduce the amount of the credit available to us (or our partners), which may impact our ability to successfully develop clean hydrogen production projects. Moreover, the accessibility of direct pay, tax equity financing, and the credit transfers market for 45V 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 45V credit still exist.

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 or 45V 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. The EPA finalized methane emissions standards for new, modified and existing oil and natural gas: required reporting of annual GHG emissions from oil and natural gas exploration and production, power plants and natural gas processing plants; gathering and boosting compression and pipeline facilities; and certain completions and workovers; incorporation of measures to reduce GHG emissions in permits for certain facilities; and restriction of GHG emissions from certain mobile sources. 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-trade” program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030, the year that the 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;

•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 sent to the Office of Administrative Law in January 2025. However, in February 2025, the Office of Administrative Law issued a Notice of Disapproval to CARB, citing clarity and incorrect procedure as grounds for its disapproval. CARB may resubmit the finalized amendments after resolving the identified issues.

The amendments also excluded clean hydrogen produced using CCS from the definition of “Renewable Hydrogen”. Clean hydrogen produced using CCS comes primarily from natural gas using a steam reformation process, which brings together natural gas and heated water in the form of steam. The output is hydrogen. Carbon dioxide is produced as a by-product of this process. The produced hydrogen constitutes clean hydrogen using CCS if the produced carbon dioxide is captured and permanently sequestered. We are still assessing the impact of these revisions on the eligibility of certain of our hydrogen and CCS projects for LCFS credits; however, to the extent CARB disfavors clean hydrogen using CCS projects from generating credits under the LCFS, our low carbon projects may not be able to capture their full value as originally estimated. This could result in certain projects becoming less or non-economic, which in turn could limit our ability to successfully pursue hydrogen and CCS projects in the future.

California's cap-and-trade program is a market-based emissions reduction program to limit GHG emissions. 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-trade program. The timing for the adoption of a protocol is unclear and it may not happen at all. Until CARB adopts a CCS protocol for cap-and-trade, the program considers GHG emissions sequestered using CCS to be no different than unabated emissions. If CARB fails to adopt a CCS protocol for cap-and-trade, 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-trade 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 and former Governors 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. In response to President Biden’s executive order calling on the EPA to revisit federal regulations regarding methane, 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. Under the final rules, states have two years to prepare and submit their plans to impose methane emissions controls on existing sources. The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial. The rules have been subject to legal challenge, and may also be repealed or modified by the current administration, though we cannot predict the substance or timing of such changes, if any.

Relatedly, beginning in 2025, certain oil and gas facilities, including those we own and operate, must pay a fee to EPA pursuant to the Inflation Reduction Act, starting at $900 per metric ton of methane emitted in 2024 and annually thereafter, with the fee rising to $1,200 in 2025 and $1,500 in 2026 and thereafter. However, compliance with the EPA’s methane rules, discussed above, would exempt an otherwise covered facility from the requirement to pay the fee. At this time, it remains uncertain whether the current administration will take any action to revise or repeal the methane charge rule or if Congress may take action to repeal or revise the IRA, including with respect to the methane charge rule.

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. In 2015, the U.S. federal government lifted restrictions on the export of domestically produced oil that allows for the sale of U.S. oil production, including ours, in additional markets.

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. For example, on January 1, 2020, the International Maritime Organization reduced the maximum sulfur content in marine fuels from 3.5% to 0.5% by weight under the International Convention for the Prevention of Pollution from Ships. Under this IMO 2020 rule, ships must either switch to low-sulfur fuels or install scrubbing facilities for emission controls, which may affect the price of and demand for varying grades of crude oil, both internationally and in California.

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. For example, in January 2020, the California Public Utilities Commission (CPUC) commenced a rulemaking to develop a long-term natural gas planning strategy to ensure safe and reliable gas systems at just and reasonable rates during what it describes as a 25-year transition from natural gas-fueled technologies to meet the state's GHG goals. In addition, several municipalities in California enacted ordinances in 2019 that restrict the installation of natural gas appliances and infrastructure in new residential or commercial construction, which could affect the retail natural gas market of our utility customers and the demand and prices we receive for the natural gas we produce. Several of these ordinances face legal challenges.

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.