We are an independent oil and natural gas exploration and production company operating properties exclusively within California. As discussed in Note 2 Chapter 11 Proceedings, we emerged from Chapter 11 proceedings on October 27, 2020. In connection with our emergence, our board of directors was reconstituted.

All financial information presented consists of our consolidated results of operations, financial position and cash flows. We have eliminated significant intercompany transactions and balances. We account for our share of oil and natural gas producing activities, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on our consolidated financial statements.

Our consolidated financial statements, including the notes thereto, have been prepared assuming we will continue as a going concern. In preparing these consolidated financial statements accounting guidance requires that the financial statements distinguish transactions and events that are directly related to our bankruptcy filing and reorganization from the ongoing operations of the business. As a result, we have classified all income, expenses, gains or losses that were incurred or realized subsequent to the petition date of our bankruptcy filing as reorganization items, net on our consolidated statement of operations. During bankruptcy, we segregated our liabilities and obligations whose treatment and satisfaction were dependent on the outcome of the Chapter 11 Cases, which were limited to our long-term debt and related accrued interest up to the petition date as “liabilities subject to compromise” on our consolidated balance sheet. Upon emergence, these allowed claims were settled in exchange for new CRC common stock, subscription rights and warrants as discussed in Note 2 Chapter 11 Proceedings.

We qualified for and adopted fresh start accounting upon emergence from Chapter 11 at which point we became a new entity for financial reporting purposes because (1) the holders of existing voting shares prior to emergence received less than 50% of our new voting shares following our emergence from bankruptcy and (2) the reorganization value of our assets immediately prior to the confirmation of the Plan was less than the post-petition liabilities and allowed claims, which were included in liabilities subject to compromise as of our emergence date. We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting.

As a result of the application of fresh start accounting and the effects of the implementation of our Plan of Reorganization, the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020. See Note 2 Chapter 11 Proceedings and Note 3 Fresh Start Accounting for additional information on our bankruptcy proceedings and the impact of fresh start accounting on our consolidated financial statements.

The process of preparing financial statements in conformity with U.S. GAAP requires management to select appropriate accounting policies and make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements and judgments on expected outcomes as well as the materiality of transactions and balances. Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments. Further, actual results may differ from estimates upon settlement. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of our consolidated financial statements.

We sell crude oil, natural gas and NGLs to marketers, California refineries and other customers that have access to transportation and storage facilities. In light of the ongoing energy deficit in California and strong demand for native crude oil production, we do not believe that the loss of any single customer would have a material adverse effect on our consolidated financial statements taken as a whole.

For the Successor period, three California refineries each accounted for at least 10%, and collectively accounted for 50%, of our oil and natural gas sales. For the 2020 Predecessor period and for the year ended December 31, 2019, two California refineries, each accounted for at least 10%, and collectively accounted for 46%, of our oil and natural gas sales. For the year ended December 31, 2018, two California refineries each accounted for at least 10%, and collectively accounted for 43%, of our oil and natural gas sales.

We allocated the reorganization value under fresh start accounting to our identifiable assets and liabilities based on their estimated fair value. Our reorganization value was less than the identifiable assets of the emerging entity and we allocated the difference to nonfinancial assets on a relative fair value basis. Our valuation approach for determining the estimated fair value of our significant assets acquired and liabilities assumed is discussed in Note 3 Fresh Start Accounting.

We use the successful efforts method to account for our oil and natural gas properties. Under this method, we capitalize costs of acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells, including permitting, land preparation and drilling costs, are initially capitalized pending a determination of whether we find proved reserves. If we find proved reserves, the costs of exploratory wells remain capitalized. Otherwise, we charge the costs of the related wells to expense. In cases where we cannot determine whether we have found proved reserves at the completion of exploration drilling, we conduct additional testing and evaluation of the wells. We generally expense the costs of such exploratory wells if we do not find proved reserves within a one-year period after initial drilling has been completed.

Proved Reserves – Proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. We have no proved oil and natural gas reserves for which the determination of economic producibility is subject to the completion of major capital investments.

Several factors could change our proved oil and natural gas reserves. For example, for long-lived properties, higher commodity prices typically result in additional reserves becoming economic and lower commodity prices may lead to existing reserves becoming uneconomic. Estimation of future production and development costs is also subject to change partially due to factors beyond our control, such as energy costs and inflation or deflation of oil field service costs. These factors, in turn, could lead to changes in the quantity of proved reserves. Additional factors that could result in a change of proved reserves include production decline rates and operating performance differing from those estimated when the proved reserves were initially recorded as well as availability of capital to implement the development activities contemplated in the reserves estimates and changes in management's plans with respect to such development activities.

We perform impairment tests with respect to proved properties when product prices decline other than temporarily, reserves estimates change significantly, other significant events occur or management's plans change with respect to these properties in a manner that may impact our ability to realize the recorded asset amounts. Impairment tests incorporate a number of assumptions involving expectations of undiscounted future cash flows, which can change significantly over time. These assumptions include estimates of future product prices, which we base on forward price curves and, when applicable, contractual prices, estimates of oil and natural gas reserves and estimates of future expected operating and development costs. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value. We recognize any impairment loss on proved properties by adjusting the carrying amount of the asset.

Unproved Properties – When we make acquisitions that include unproved properties, we assign values based on estimated reserves that we believe will ultimately be proved. As exploration and development work progresses and if reserves are proved, we transfer the book value from unproved to proved based on the initially determined rate per BOE. If the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of the related properties would be expensed.

Impairments of unproved properties are primarily based on qualitative factors including intent of property development, lease term and recent development activity. The timing of impairments on unproved properties, if warranted, depends upon management's plans, the nature, timing and extent of future exploration and development activities and their results. We recognize any impairment loss on unproved properties by providing a valuation allowance.

Depreciation, Depletion and Amortization – We determine depreciation, depletion and amortization (DD&A) of oil and natural gas producing properties by the unit-of-production method. Our unproved reserves are not subject to DD&A until they are classified as proved properties. We amortize acquisition costs over total proved reserves, and capitalized development and successful exploration costs over proved developed reserves. Our gas and power plant assets are depreciated over the estimated useful lives of the assets, using the straight-line method, with expected initial useful lives of the assets of up to 30 years. Other non-producing property and equipment is depreciated using the straight-line method based on expected initial lives of the individual assets or group of assets of up to 20 years.

We expense annual lease rentals, the costs of injection used in production and exploration, and geological, geophysical and seismic costs as incurred. Costs of maintenance and repairs are expensed as incurred, except that the costs of replacements that expand capacity or add proven oil and natural gas reserves are capitalized.

Transfers between levels, if any, are recognized at the end of each reporting period. We apply the market approach for certain recurring fair value measurements, maximize our use of observable inputs and minimize use of unobservable inputs. We generally use an income approach to measure fair value when observable inputs are unavailable. This approach utilizes management's judgments regarding expectations of projected cash flows and discount rates.

Commodity derivatives are carried at fair value. We utilize the mid-point between bid and ask prices for valuing these instruments. Our commodity derivatives comprise over-the-counter bilateral financial commodity contracts, which are generally valued using industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and current market and contracted prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable data or are supported by observable prices based on transactions executed in the marketplace. We classify these measurements as Level 2. Commodity derivatives are the most significant items on our consolidated balance sheets affected by recurring fair value measurements.

Our property, plant and equipment (PP&E) may be written down to fair value if we determine that there has been an impairment. The fair value is determined as of the date of the assessment using discounted cash flow models based on management’s expectations for the future. Inputs include estimates of future production, prices based on commodity forward price curves, inclusive of market differentials, as of the date of the estimate, estimated future operating and development costs and a risk-adjusted discount rate.

We derive substantially all of our revenue from sales of oil, natural gas and NGLs and associated hedging activities, with the remaining revenue generated from sales of electricity and trading activities related to storage and managing excess pipeline capacity. Revenues are recognized when control of promised goods is transferred to our customers, in an amount that reflects the consideration we expect to receive in exchange for those goods.

Our receivables from customers relate to sales of our commodity products, trading activities and joint interest billings. Credit exposure for each customer is monitored for outstanding balances and current activity. We actively manage our credit risk by selecting counterparties that we believe to be financially sound and continue to monitor their financial health. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified. We believe exposure to counterparty credit-related losses at December 31, 2020 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods predominantly comprise oil and natural gas liquids (NGLs), which are valued at the lower of cost or net realizable value. Inventories, by category, are as follows:

The fair value of our derivative contracts are netted when a legal right of offset exists with the same counterparty with an intent to offset. Since we did not apply hedge accounting to our commodity derivatives for any of the periods presented, we recognized fair value adjustments, on a net basis, in our consolidated statements of operations. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not accounted for as cash-flow or fair-value hedges.

All of the pre-emergence outstanding stock-based awards under our then long-term incentive plan were cancelled upon emergence. As of December 31, 2020, no awards were issued under our new long-term incentive plan. The shares issuable under the new long-term incentive plan had been authorized by the bankruptcy court and the terms of the new long-term incentive plan were approved by our new board of directors in January 2021. In accordance with our new long-term incentive plan, we reserved 9.3 million shares of common stock for future issuances, subject to adjustment.

Basic earnings (loss) per share for all periods presented equals net income (loss) divided by the weighted average number of our shares outstanding during the period including participating securities. Diluted earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of our shares outstanding including participating securities. Potentially dilutive securities for the Predecessor periods included warrants, stock options, restricted shares and performance units, when applicable. Potentially dilutive securities for the Successor periods included warrants. We compute basic and diluted earnings per share (EPS) using the two-class method required for participating securities, when applicable. Certain restricted and performance stock awards are considered participating securities when such shares have non-forfeitable dividend rights, which participate at the same rate as common stock.

Under the two-class method, net income allocated to participating securities is subtracted from net income attributable to common stock in determining net income available to common stockholders. In loss periods, no allocation is made to participating securities because the participating securities do not share in losses.

We recognize the fair value of asset retirement obligations (ARO) in the period in which a determination is made that a legal obligation exists to dismantle an asset and reclaim or remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The fair value of the retirement obligation is based on future retirement cost estimates and incorporates many assumptions such as time of abandonment, current regulatory requirements, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, we capitalize the cost by increasing the related PP&E balances. If the estimated future cost or timing of cash flow changes, we record an adjustment to both the ARO and PP&E. Over time, the liability is increased and expense is recognized for accretion, and the capitalized cost is recovered over either the useful life of our facilities or the unit-of-production method for our minerals. As part of fresh start accounting, the ARO liability was adjusted to the estimated fair value as described in Note 3 Fresh Start Accounting.

At certain of our facilities, we have identified ARO that are related mainly to plant and field decommissioning, including plugging and abandonment of wells. In certain cases, we do not know or cannot estimate when we would perform the ARO work and, therefore, we cannot reasonably estimate the fair value of these liabilities. We will recognize ARO in the periods in which sufficient information becomes available to reasonably estimate their fair values. Additionally, for certain plants, we do not have a legal obligation to decommission them and, accordingly, we have not recorded a liability.


	Successor		Predecessor		Predecessor
(in millions)	November 1, 2020 - December 31, 2020		January 1, 2020 - October 31, 2020		December 31, 2019
Beginning balance	$	593	$	517	$	433
Liabilities incurred, capitalized to PP&E	—		—		(5)
Liabilities settled and paid	(5)		(12)		(26)
Accretion expense	8		33		36

Dispositions, reduction to PP&E	—		(4)		(10)
Other	1		2		4
Revisions in estimated cash flows	—		—		85
Impact of fresh start accounting	—		57		—
Ending balance	$	597	$	593	$	517

Current portion	$	50	$	50	$	28
Non-current portion	$	547	$	543	$	489

Idle well regulations enacted in the first quarter of 2019 require operators to either (1) submit annual idle well management plans describing how they will plug and abandon or reactivate a specified percentage of long-term idle wells or (2) pay additional annual fees and perform additional testing every six years to retain greater flexibility to return long-term idle wells to service in the future. These regulations provide a six-year implementation period for testing existing idle wells not scheduled for plugging and abandonment. Newly idle wells must be tested within two years after becoming idle and, thereafter, are subject to the same testing schedule for existing idle wells.

In the normal course of business, we are involved in lawsuits, claims and other environmental and legal proceedings and audits. We accrue reserves for these matters when it is probable that a liability has been incurred and the liability can be reasonably estimated. In addition, we disclose, if material, in aggregate, our exposure to losses in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. We review our loss contingencies on an ongoing basis.

Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings, or other factors.

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases. Deferred tax assets are recognized when it is more likely than not that they will be realized. We periodically assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized.

We recognize the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a tax authority. We recognize interest and penalties, if any, related to uncertain tax positions as a component of the income tax provision. No interest or penalties related to uncertain tax positions were recognized in the financial statements for the periods presented.

Our share of production and reserves from operations in the Wilmington field is subject to contractual arrangements similar to production-sharing contracts (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 PSC-type contracts represented approximately 18% of our production for both the Successor and Predecessor periods in 2020.

In line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under such contracts in 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. 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.

All of our employees participate in postretirement benefit plans we sponsor. These plans are primarily funded as benefits are paid. In addition, a small number of our employees also participate in defined benefit pension plans sponsored by us. We recognize the net overfunded or underfunded amounts in the consolidated financial statements at each measurement date.

We determine our defined benefit pension and postretirement benefit plan obligations based on various assumptions and discount rates. The discount rate assumptions used are meant to reflect the interest rate at which the obligations could effectively be settled on the measurement date. We estimate the rate of return on assets with regard to current market factors but within the context of historical returns.

Pension plan assets are measured at fair value. Publicly registered mutual funds are valued using quoted market prices in active markets. Commingled funds are valued at the fund units’ net asset value (NAV) provided by the issuer, which represents the quoted price in a non-active market. Guaranteed deposit accounts are valued at the book value provided by the issuer.

As part of fresh start accounting, we measured our pension and postretirement medical plan assets and liabilities at fair value as described in Note 3 Fresh Start Accounting. Actuarial gains and losses that had not yet been recognized in the Predecessor period through income, which were recorded in accumulated other comprehensive income within equity, were eliminated as part of fresh start accounting. In the Successor period, we recorded actuarial gains and losses, net of taxes, in accumulated other comprehensive income until they are amortized as a component of net periodic benefit cost.


	Successor		Predecessor
(in millions)	December 31, 2020		December 31, 2019
Accrued employee-related costs	$	72	$	116
Accrued taxes other than on income	36		57
Asset retirement obligations	50		28
Accrued interest	1		13
Lease liability	7		28
Fair value of derivatives	50		—
Payments due to counterparties on commodity contracts	21		5
Other	24		66
Accrued liabilities	$	261	$	313


	Successor		Predecessor
(in millions)	December 31, 2020		December 31, 2019
Asset retirement obligations	$	547	$	489
Deferred compensation and postretirement	184		182
Lease liability	35		38
Fair value of derivatives	6		—
Payments due to counterparties on commodity contracts	31		—
Other	19		11
Other long-term liabilities	$	822	$	720


	Successor		Predecessor
	November 1, 2020 - December 31, 2020		January 1, 2020 - October 31, 2020
(in millions)
Gain on settlement of liabilities subject to compromise	$	—	$	4,022
Unamortized deferred gain and issuance costs, net	—		125
Junior debtor-in-possession exit fee	—		(12)
Acceleration of unrecognized compensation expense on cancelled stock-based compensation awards	—		(5)
Write-off of prepaid directors and officers' insurance premiums	—		(2)
Total non-cash reorganization items	$	—	$	4,128
Legal, professional and other, net	(3)		(43)
Debtor-in-possession financing costs	—		(25)
Total reorganization items, net	$	(3)	$	4,060


	Successor		Predecessor
	November 1, 2020 - December 31, 2020		January 1, 2020 - October 31, 2020		Year ended December 31,
					2019		2018
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	(8)	$	(79)	$	(425)	$	(433)

Supplementary Disclosure of Noncash Investing and Financing Activities
Successor common stock, Subscription Rights and Warrants issued pursuant to the Plan			$	(494)
Successor common stock issued for the junior debtor-in-possession exit fee pursuant to the Plan			$	(12)
Successor common stock and EHP Notes issued for acquisition of noncontrolling interest pursuant to the Plan			$	(561)
Successor common stock issued for a backstop commitment premium pursuant to the Plan			$	(52)
Warrant issued to a joint venture partner					$	(3)
Common stock issued as part of the acquisition of Elk Hills unit							$	(51)