UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission File Number 001-36478

California Resources Corporation

Securities registered pursuant to Section 12(b) of the Act:

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.  See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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.

On February 7, 2024, we entered into a definitive agreement and Supplementary Data, Note 14 Chapter 11 Proceedings plan of merger (Merger Agreement) to combine with Aera Energy, LLC (Aera) in an all-stock transaction (Aera Merger) with an effective date of January 1, 2024. Aera is a leading operator of mature fields in California, primarily in the San Joaquin and Ventura basins, with high oil-weighted production.

Pursuant to the Merger Agreement, we have agreed to issue 21,170,357 shares of common stock (subject to customary adjustments in the event of stock splits, dividend paid in stock and Note 15 Fresh Start Accounting for similar items) plus an additional information onnumber of shares determined by reference to the dividends declared by us having a record date between the effective date and closing as more fully described in the Merger Agreement. Under the terms of the Plan,Merger Agreement, we have also agreed to assume Aera’s outstanding long-term indebtedness of $950 million at closing. We expect to repay a significant portion of this indebtedness with cash on hand and borrowings under our emergence from bankruptcyRevolving Credit Facility. We intend to refinance the balance through one or more debt capital markets transactions and, applicationonly to the extent necessary, borrowings under a bridge loan facility provided by Citigroup Global Markets, Inc. (the Bank). Under the terms of fresh start accountingour debt commitment letter with the Bank, it has committed, subject to satisfaction of customary conditions, to provide us with an unsecured 364-day bridge loan facility in an aggregate principal amount of $500 million (Bridge Loan Facility).

Our strategyUpon completion of the transaction, we currently expect our existing stockholders to own approximately 77.1% of the combined company and the existing Aera owners to own approximately 22.9% of the combined company, on a fully diluted basis. The Aera Merger is expected to continue to develop our oil and natural gas assets and while pursuing opportunitiesclose in the emerging industriessecond half of decarbonization2024. Post closing of the Aera Merger, and energy transition. To accomplishsubject to Board approval, we expect to increase our strategy, we have developed the following key priorities:quarterly dividend.

In February 2024, we entered into an agreement to sell our cash flow from operations from volatility0.9-acre Fort Apache real estate property in the commodities market. Additionally, we are committed to maintaining low leverage and a strong liquidity position. Over the next several years, we are targeting investingHuntington Beach, California for approximately 25% of our operating cash flow for shareholder returns and other strategic opportunities. In 2021, we adopted a dividend policy by which we expect to pay a quarterly dividend of $0.17 per share of our common stock, subject to final quarterly approval by our Board of Directors. We have also adopted a $350 million share repurchase program that is expected to run through December 31, 2022. We have repurchased 4,089,988 shares as of December 31, 2021 at an average price of $36.08 per share.$10 million.

As of December 31, 2021,2023, our proved reserves totaled an estimated 480377 MMBoe, of which 343256 MMBbl were crude oil and condensate reserves, 4135 MMBbl were NGL reserves and 576518 BcF, or 9686 MMBoe, were natural gas reserves.

As of December 31, 2021,2023, we held approximately 1.91.7 million net mineral acres, the largest non-governmentalprivately owned mineral acreage position in California. Our operated asset base spans 9997 distinct fields with approximately 10,0009,000 net operated wells. We had average net production of approximately 10086 MBoe/d (60% oil) for the year ended December 31, 2021. Our average net revenue interest was 85% as of December 31, 2021. From time to time, we will assess our robust portfolio of assets for divestitures.2023.

The following table highlights key information about our operations as of and for the year ended December 31, 2021:2023:

TheCommercial petroleum development in the San Joaquin basin contains some of the largest oil fields in the United States based on cumulative production and proved oil and natural gas reserves. Commercial petroleum development 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.

At Elk Hills we operate efficient natural gas processing facilities, including a state-of-the-art cryogenic gas plant, with a combined gas processing capacity of over 520330 MMcf/d. Additionally, our Elk Hills power plant generates sufficient electricity to operatepower our oil and gas operations at the Elk Hills field, and sellsoffers excess power to the California Independent System Operator (CAISO) wholesale energy marketplace. We also market and a utility.power plant capacity in excess of our internal needs to the CAISO Resource Adequacy (RA) marketplace. Our operations at Elk Hills also include an advanced central control facility and remote automation control on over 95% of the producing wells.

We have a large ownership interest in several of the largest existing oil fields in the San Joaquin basin including Buena Vista and Coles Levee. We have also been successfully developing steamfloods in our Kern Front operations.

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. Our significant mineral acreage positionWe are in the Sacramento basin gives us the option for future development and rapidprocess of pursuing permits to facilitate production growth and develop this resource, leveraging the existing infrastructure already in an attractive natural gas price environment.place.

During the fourth quarter of 2021, weWe divested a vast majority of our assets in the Ventura basin. Otherbasin other than a de minimis non-operated asset, during the fourth quarter of 2021 and the first quarter of 2022. We expect the sale of our remaining Ventura basin assets are expected to be soldasset could occur in the first half of 2022.2024.

Other than the basins described above, we also have mineral interests in undeveloped acreage throughout California including in the Salinas basin and the Santa Maria basin.

The following table summarizes our gross and net developed and undeveloped mineral acreage as of December 31, 2021.2023.

At December 31, 2021, 69%2023, 77% of our total net mineral interest position was held in fee and the remainder was leased. Of our leased acreage, approximately 59%87% 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 72,0002,000 net mineral acres will expire in 2022, 46,0002024, 21,000 net mineral acres will expire in 20232025 and 34,00014,000 net mineral acres will expire in 2024.2026. These leases represent 13%4% of our total net undeveloped acreage and 8%2% of our total net acreage as of December 31, 20212023 and these expirations, should they occur, would not have a material adverse impact 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.

Oil, natural gas and NGL production for our two largest fields 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 are 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 15%18% of our total production for the year ended December 31, 2021.2023.

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:

The components of the changes to our proved reserves during the year ended December 31, 20212023 were as follows:

The total changes to our proved undeveloped reserves during the year ended December 31, 20212023 were as follows:

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.

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 Vice PresidentDirector of Reserves has primary responsibilityis the technical person who is primarily responsible for overseeing the preparation of our reserves estimates. WithHe has over 2515 years of technical and leadership experience in the upstream oil and gas industry, she has been involved with all stages of petroleum exploration and developmentprojects ranging from appraisal of new discoveriesprimary production reservoirs to enhanced oil recovery methods in mature fields. Shefloods. He holds a MasterBachelor of Business Administration from Pepperdine University, as well as bachelor’s and master’s degreesScience degree in GeologyPetroleum Engineering from the UniversityColorado School of California, Santa Barbara.Mines.

We have an Oil and Gas Reserves Review Committee (Reserves Committee), consisting of senior corporate officers, which reviewed and approved our oil and natural gas reserves for 2021.2023. The Reserves Committee annually reports its findings to the Audit Committee.

Ryder Scott and Netherland, Sewell & Associates, Inc. (NSAI) werewas engaged to provide independent audits of our reserves estimates for our fields. For the year ended December 31, 2021, Ryder Scott audited 47% of our total proved reserves.2023, NSAI audited 35%88% 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 it had resolved its 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. Both of ourOur independent reserve engineers issued an unqualified audit opinion on the applicable portions of our proved reserves as of December 31, 2021,2023, which areis attached as Exhibit 99.1 and 99.2, respectively, to this Form 10-K and incorporated herein by reference.

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.

The following table sets forth information on our development wells where drilling was either in progress or pending completion as of December 31, 2021.2023.

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 89%96% as of December 31, 2021.2023. 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, 2021,2023, excluding wells that have been idle for more than five years:

We have had minimal investment in exploration activity in recent years, and our 20222024 capital plan does not allocate any capital towards exploration drilling. Although we do not anticipate exploration drilling in the near term, we do have a portfolio of 65 exploration prospects in the San Joaquin and Sacramento basins that we may pursue in the future. We also have an extensive 3D and 2D seismic library that we use to develop and refine exploration prospects.

The prices paid by California refiners are typically based on local third-party indicespostings that are closely tied to Brent prices. International waterborne-based Brent prices are usedrelevant 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 addition to selling natural gas, we also use natural gas in steam generation for our steamfloods and power generation. As a result, the positive impact of higher natural gas prices is partially offset by higher operating costs of our steamflood projects and power generation, but higher prices still have a net positive effect on our operating results due to net higher revenue. Conversely, lower natural gas prices lower these operating costs but have a net negative effect on our financial results.

We currently hold transportation capacity contracts to transport all of our natural gas volumes for multiple years.

We currently have a ship-or-pay pipeline transportation contract for 6,500approximately 6,100 barrels per day of NGLs.NGLs through March 2026. Our contract to transport NGLs requires us to cash settle any shortfall between the committed quantities and volumes actually shipped. We have met all our shipping commitments under this contract.contract for the periods presented.

We have short-term commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. As of December 31, 2021,2023, we had oil delivery commitments of 52 MBbl/d through March 2022,averaging 9 MMBbl in 2024 and 1 MMBbl in 2025, NGL delivery commitments of 12 MBbl/d1 MMBbl through March 20222024 and natural gas delivery commitments of 32 MMcf/d15 Bcf through October 2022.December 2024. We generally have significantly more production than the amounts committed for delivery and have the ability to secure additional volumes of products as needed. These commitments are typically index-based contracts with prices set at the time of delivery.

We protect our operating cash flow from volatility in the commodities market through our hedging strategy. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. Our prior credit agreement included covenants that required us to maintain a certain level of hedges at all times. Our current Revolving Credit Facility includes covenants that require us to maintain a certain level of hedges overunless the ratio of our reasonably anticipated oil production from our proved reserves.indebtedness to Consolidated EBITDAX (as defined in the Revolving Credit Facility) is less than or equal to 1.5:1.0. We have also entered into incrementala limited number of hedges above and beyond those that were required for certain periods. In prior years, these requirements for some time periods and will continue tohedges prevented us from realizing the full benefits of price increases. We continuously evaluate our hedging strategy based onto take into account changes in prevailing market prices and conditions.

Our competitors are primarily other exploration and production companies that produce oil, natural gas and NGLs. We compete locally against small independent producers and a major international oil companiescompany who operate in California. We also compete with foreign oil and gas companies because California imports approximately 70%75% of the oil it consumes and virtually all of that arrives from waterborne sources.consumes. 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 similar characteristics to the low-carbon intensity oil produced from our fields. 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. Higher commodity prices could intensify competition for drilling and workover rigs, pipe, other oil field equipment and personnel. AtHowever, in the current commodity price levels,environment, we have experiencedanticipate modest price increases for materials and services as contracts are renewed.renewed in the future. We believe our relative size and activity levels,level, compared to other in-state producers, favorably influences the pricing we receive from third-party providers in the markets in which we operate.

We also face competition in our oil and natural gas operations from other sources of energy, including wind and solar power. These products compete directly with the electricity we generate from our Elk Hills power plantsplant and indirectly as substitutes for oil, natural gas and NGLs. We expect competition from these sources to intensify in the future due to technological advances and as California continues to develop renewable energy and implements climate-related policies.