We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We provide ample, affordable and reliable energy in a safe and responsible manner, to support and enhance the quality of life of Californians and the local communities in which we operate. We do this through the development of our broad portfolio of assets while adhering to our commitment to making value-based capital investments. Further, we are committed to energy transition and have some of the lowest carbon intensity production in the United States. Through our subsidiary, Carbon TerraVault, we are in the early stages of developing several carbon capture and sequestration projects in California. Separately, we are evaluating the feasibility of a carbon capture system to be located at our Elk Hills power plant (CalCapture). We are also pursuing multiple solar projects for supplying the grid (front-of-the-meter solar) and powering our operations (behind-the-meter solar). 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.

We emerged from bankruptcy on October 27, 2020 with a new board of directors, new equity ownersqualified for and a significantly improved financial position. Under the plan of reorganization approved by the Bankruptcy Court (the Plan), all of our outstanding pre-emergence indebtedness under our credit facilities and senior notes was cancelled. At emergence, we entered into a new revolving credit facility with a $1.2 billion borrowing base and $540 million of lender commitments (Revolving Credit Facility). Our post-emergence capital structure also included a $200 million second lien term loan (Second Lien Term Loan), and $300 million of secured notes due 2027 issued by our wholly-owned subsidiary in connection with our acquisition of our partner's interest in our Elk Hills Power joint venture (EHP Notes).

As of December 31, 2021, we held approximately 1.9 million net mineral acres, the largest privately heldnon-governmental mineral acreage position in California, consisting of approximately 2.1 million net mineral acres spanning four of California's major oil and natural gas basins.California. Our operated asset base spans 13099 distinct fields with approximately 12,00010,000 operated wells. OurWe had average net production of approximately 111100 MBoe/d (62%(60% oil) for the year ended December 31, 2020.2021. Our average net revenue interest was approximately 87%85% as of December 31, 2020. 2021. From time to time, we will assess our robust portfolio of assets for divestitures.

The following table highlights key information about our operations as of and for the year ended December 31, 2020:2021:

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 in the basin began in the 1800s. The basin contains multiple stacked formations throughout its areal extent, and we believe that the San Joaquinthis basin provides appealing opportunities for field 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. Approximately 75% of California’s total daily oil production for 2018 was produced in the San Joaquin basin, according to CalGEM.

We hold substantially all the working, surface and mineral interests in the Elk Hills field, which is our largest producing asset in the San Joaquin Basin and one of the largest fields in the continental U.S.United States.

At Elk Hills we also operate efficient natural gas processing facilities, including a state-of-the-art cryogenic gas plant, with a combined gas processing capacity of over 520 MMcf/d. Additionally, our Elk Hills power plant generates sufficient electricity to operate the field, and sells excess power to the wholesale market and a utility. 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.

We believe our extensive 3D seismic library, which covers approximately 800,000 acres in the San Joaquin basin, or approximately 50% of our gross mineral acreage in this basin, gives us a competitive advantage in field development and further exploration.

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 position in the Sacramento basin gives us the option for future development and rapid production growth in an attractive natural gas price environment.

The following table summarizes our gross and net developed and undeveloped mineral acreage as of December 31, 2020.2021.

Approximately 65%At December 31, 2021, 69% of our total net mineral interest position iswas held in fee and the remainder iswas leased. Of our leased acreage, approximately 49%59% 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 tentwenty 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.

Approximately 58,000 net mineral acres will expire in 2021, 119,000If we are not able to establish production or otherwise extend lease terms, approximately 72,000 net mineral acres will expire in 2022, and 57,00046,000 net mineral acres will expire in 2023 if production is not established and we take no other action to extend the terms of the leases.34,000 net mineral acres will expire in 2024. These leases expiring in the next three years represented 17%represent 13% of our total net undeveloped acreage atand 8% of our total net acreage as of December 31, 20202021 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 we will need to do so in the future.

The following table sets forth information regarding our production volumes, average realized and benchmark prices and operating costs per Boe for the years ended December 31, 2020, 2019 and 2018. periods presented.

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. The measures taken to address the recent industry downturn demonstrate that weWe can significantly reducequickly scale our operating costs in response to prevailing market conditions. We further believe that a significant portion of our operating costs are variable over the lifecycle of our fields. We actively manage our fields to optimize production and minimize costs in a safe and responsible manner throughout their lifecycles.

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to PSC-type contractsPSCs 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 PSC-type contractsPSCs represented 18%15% of our total production for the year ended December 31, 2020.2021.

In addition, in line with industry practice for reporting PSC-type contracts,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 PSC-type contracts.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 components of the changes to our proved reserves during the year ended December 31, 20202021 were as follows:

The total changes to our proved undeveloped reserves during the year ended December 31, 20202021 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 President of Reserves and Corporate Development has primary responsibility for overseeing the preparation of our reserves estimates. She has 20With over 25 years of technical and leadership experience as an energy sector engineer including as a Senior Reservoir Engineerin the oil and gas industry, she has been involved with Ryder Scott Company, L.P. (Ryder Scott). She is a memberall stages of the Societypetroleum exploration and development from appraisal of Petroleum Engineers (SPE) for which she served as past chair of the U.S. Registration Committee.new discoveries to enhanced recovery methods in mature fields. She holds a Master of Business Administration from the Massachusetts Institute of Technology, a Master of EngineeringPepperdine University, as well as bachelor’s and master’s degrees in Petroleum EngineeringGeology from the University of Houston and a Bachelor of Science from the University of Florida. She is also a registered Professional Engineer in the state of Texas.California, Santa Barbara.

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 2020.2021. The Reserves Committee annually reports its findings to the Audit Committee.

Ryder Scott and Netherland, Sewell & Associates, Inc. (NSAI) were engaged to provide independent audits of our reserves estimates for our fields. For the year ended December 31, 2020,2021, Ryder Scott audited 53%47% of our total proved reserves. NSAI audited 31%35% of our total proved reserves. Over 95% of our total 2020 proved reserves were audited by independent auditors at some time during the four-year period ended December 31, 2020.

Our independent reserve engineers examined the assumptions underlying our reserves estimates, adequacy and quality of our work product and estimates of future production rates, net revenues, and the present value of such net revenues.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 SPESociety 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 our independent reserve engineers issued an unqualified audit opinion on the applicable portions of our proved reserves as of December 31, 2020,2021, which are attached as Exhibit 99.1 and 99.2, respectively, to this Form 10-K and incorporated herein by reference.

Based on our reserves report as of December 31, 2020, we have 591 gross drilling locations attributable to our proved undeveloped reserves. We use production data and experience gained from our development programs to identify and prioritize this provenour drilling inventory. These drillingDrilling locations are included in our reserves only after we have adopted a development plan to drill them within a five-year time frame of the original reserve booking. As a result of rigorous technical evaluation of geologic and engineering data, we can estimate with reasonable certainty

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.owned, including outside operated wells. Net wells represent wells reduced to our fractional interest.