Notes to Consolidated Financial Statements
NOTE 1 NATURE OF BUSINESS, SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER
Nature of Business
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.
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 subsidiaries.
Basis of Presentation
We have prepared this report in accordance with United States (U.S.) generally accepted accounting principles (U.S. GAAP) and the rules and regulations of the U.S. Securities and Exchange Commission applicable to annual financial information.
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.
Certain prior year amounts have been reclassified to conform to the current year presentation. We reclassified deferred gain and issuance costs, net to be presented within the long-term debt line on the face of our consolidated balance sheets.
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.
Use of Estimates
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.
Concentration of Customers
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.
Critical Accounting Policies
Fresh Start Accounting and Allocation of Reorganization Value
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.
Property, Plant and Equipment (PP&E)
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.
Fair Value Measurements
Our assets and liabilities measured at fair value are categorized in a three-level fair-value hierarchy, based on the inputs to the valuation techniques:
Level 1—using quoted prices in active markets for the assets or liabilities;
Level 2—using observable inputs other than quoted prices for the assets or liabilities; and
Level 3—using unobservable inputs.
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.
The carrying amounts of cash and other on-balance sheet financial instruments, other than fixed-rate debt, approximate fair value.
Significant Accounting Policies
Revenue Recognition
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.
See Note 18 Revenue Recognition where we present disaggregated revenues by commodity type.
Allowance for Credit Losses
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.
Inventories
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:
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Successor
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Predecessor
|
|
(in millions)
|
2020
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|
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2019
|
|
Materials and supplies
|
$
|
58
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|
|
|
$
|
64
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|
|
Finished goods
|
3
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|
|
|
3
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Total
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$
|
61
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|
|
|
$
|
67
|
|
Derivative Instruments
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.
Stock-Based Incentive Plans
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.
Earnings Per Share
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.
Asset Retirement Obligations
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.
The following table presents a rollforward of our ARO.
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Successor
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Predecessor
|
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Predecessor
|
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(in millions)
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November 1, 2020 - December 31, 2020
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|
January 1, 2020 - October 31, 2020
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|
December 31, 2019
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|
Beginning balance
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$
|
593
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|
|
|
$
|
517
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|
|
$
|
433
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|
|
Liabilities incurred, capitalized to PP&E
|
—
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—
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(5)
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Liabilities settled and paid
|
(5)
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(12)
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(26)
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Accretion expense
|
8
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|
|
|
33
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|
|
36
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|
|
|
|
|
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|
|
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Dispositions, reduction to PP&E
|
—
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|
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|
(4)
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(10)
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Other
|
1
|
|
|
|
2
|
|
|
4
|
|
|
Revisions in estimated cash flows
|
—
|
|
|
|
—
|
|
|
85
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|
|
Impact of fresh start accounting
|
—
|
|
|
|
57
|
|
|
—
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|
|
Ending balance
|
$
|
597
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|
|
|
$
|
593
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|
|
$
|
517
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|
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Current portion
|
$
|
50
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|
|
|
$
|
50
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|
|
$
|
28
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|
|
Non-current portion
|
$
|
547
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|
|
|
$
|
543
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|
|
$
|
489
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|
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.
Other Loss Contingencies
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.
Income Taxes
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.
Production-Sharing Type Contracts
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.
Pension and Postretirement Benefit Plans
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.
Cash
As of December 31, 2020, our cash on hand was $28 million, which was unrestricted. Cash at December 31, 2019 included approximately $3 million that was restricted under one of our joint venture (JV) agreements and approximately $14 million was unrestricted.
Other Current Assets
Other current assets, net consisted of the following:
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|
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|
|
Successor
|
|
|
Predecessor
|
|
(in millions)
|
December 31, 2020
|
|
|
December 31, 2019
|
|
Amounts due from joint interest partners, net(a)
|
$
|
42
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|
|
|
$
|
70
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|
|
Derivative assets
|
—
|
|
|
|
39
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|
|
Prepaid expenses
|
20
|
|
|
|
19
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|
|
Other
|
1
|
|
|
|
2
|
|
|
Other current assets, net
|
$
|
63
|
|
|
|
$
|
130
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|
(a)As of December 31, 2020, we had no allowance for credit losses as a result of the adoption of fresh start accounting. Included in the balance as of December 31, 2019 was a $19 million allowance for credit losses against amounts due from joint interest partners.
Accrued Liabilities
Accrued liabilities consisted of the following:
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|
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Successor
|
|
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Predecessor
|
|
(in millions)
|
December 31, 2020
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|
|
December 31, 2019
|
|
Accrued employee-related costs
|
$
|
72
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|
|
|
$
|
116
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|
|
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
|
|
As of December 31, 2020, accrued employee-related costs included approximately $5 million of payroll taxes deferred under COVID-19 relief, half of which was due on or before December 31, 2021 with the remainder due on or before December 31, 2022.
Other Long-Term Liabilities
Other long-term liabilities consisted of the following:
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|
|
|
|
|
|
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
|
|
Reorganization Items, net
Reorganization items, net consisted of the following (in millions):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
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|
|
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
|
|
Supplemental Cash Flow Information
Supplemental disclosures to our consolidated statements of cash flows, excluding leases, are presented below (in millions):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
NOTE 2 CHAPTER 11 PROCEEDINGS
On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code (Chapter 11 Cases) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court). The Chapter 11 Cases were jointly administered under the caption In re California Resources Corporation, et al., Case No. 20-33568 (DRJ). We filed with the Bankruptcy Court, on July 24, 2020, the Debtors’ Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code and, on October 8, 2020, the Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (as amended, supplemented or modified, the Plan). On October 13, 2020, the Bankruptcy Court confirmed the Plan, which was conditioned on certain items such as obtaining exit financing. The conditions to effectiveness of the Plan were satisfied and we emerged from Chapter 11 on October 27, 2020 (Effective Date). See Note 3 Fresh Start Accounting regarding the use of an accounting convenience date for the date of our emergence.
During the course of the Chapter 11 Cases, the Bankruptcy Court granted the relief requested in certain motions, authorizing payments of pre-petition liabilities with respect to certain employee compensation and benefits, taxes, royalties, certain essential vendor payments and insurance and surety obligations, which allowed our business operations to continue uninterrupted during the pendency of the Chapter 11 Cases. Payments for transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.
Missed Interest Payments and Forbearance
On May 15, 2020, we did not make an interest payment of approximately $4 million on our 2024 Notes. The indenture governing the 2024 Notes provided for a 30-day grace period and the payment was made on June 12, 2020.
On May 29, 2020, we did not pay approximately $51 million in the aggregate of interest due under our 2017 Credit Agreement and 2016 Credit Agreement. Our failure to make those interest payments constituted events of default under the 2017 Credit Agreement, 2016 Credit Agreement and, as a result of cross default, under the 2014 Revolving Credit Facility.
On June 2, 2020, we entered into forbearance agreements (Forbearance Agreements) with (i) certain lenders of a majority of the outstanding principal amount of the loans under the 2014 Revolving Credit Facility, (ii) certain lenders of a majority of the outstanding principal amount of the loans under the 2016 Credit Agreement, and (iii) certain lenders of a majority of the outstanding principal amount of the loans under the 2017 Credit Agreement. Pursuant to the Forbearance Agreements, the lenders who were parties to the Forbearance Agreements agreed to forbear from exercising any remedies under the 2014 Revolving Credit Facility, 2016 Credit Agreement and 2017 Credit Agreement with respect to our failure to make the aforementioned interest payments, initially through June 14, 2020 and subsequently through July 15, 2020.
On June 15, 2020, we did not make an interest payment of approximately $72 million on our Second Lien Notes. The indenture governing the Second Lien Notes provides for a 30-day grace period, which expired on July 15, 2020. We did not make the July 15, 2020 interest payment and commenced bankruptcy proceedings.
Commencement of Bankruptcy Proceedings
The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the 2014 Revolving Credit Facility, 2016 Credit Agreement, 2017 Credit Agreement, and the indentures governing the Second Lien Notes, 2021 Notes and 2024 Notes, resulting in the automatic and immediate acceleration of all of our outstanding pre-petition long-term debt. Any efforts to enforce payment obligations related to the acceleration of our long-term debt were automatically stayed by the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement were subject to the applicable provisions of the Bankruptcy Code.
Upon the Effective Date, the balances of the 2016 Credit Agreement, 2017 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes were cancelled pursuant to the terms of the Plan, resulting in a gain of approximately $4 billion included in "Reorganization items, net" on our consolidated statement of operations.
Debtor-in-Possession Credit Agreements
On July 23, 2020, we entered into a Senior Secured Superpriority DIP Credit Agreement with JP Morgan, as administrative agent, and certain other lenders (Senior DIP Credit Agreement), which provided for the senior DIP facility in an aggregate principal amount of up to $483 million (Senior DIP Facility). The Senior DIP Facility included a $250 million revolving facility which was primarily used by us to (i) fund working capital needs, capital expenditures and additional letters of credit during the pendency of the Chapter 11 Cases and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Senior DIP Facility. Following a hearing, the Bankruptcy Court entered a final order on August 14, 2020, which approved the Senior DIP Facility on a final basis. The Senior DIP Facility also included (i) a $150 million letter of credit facility which was used to redeem letters of credit outstanding under the 2014 Revolving Credit Facility as issued under the Senior DIP Facility, and (ii) $83 million of term loan borrowings which were used to repay a portion of the 2014 Revolving Credit Facility. The Senior DIP Facility allowed for the issuance of an additional $35 million of letters of credit.
On July 23, 2020, we entered into a Junior Secured Superpriority DIP Credit Agreement with Alter Domus, as administrative agent, and certain lenders (Junior DIP Credit Agreement), which provided for a junior DIP facility in an aggregate principal amount of $650 million (Junior DIP Facility and together with the Senior DIP Facility, the DIP Facilities). The proceeds of the Junior DIP Facility were used to (i) refinance in full all remaining obligations under the 2014 Revolving Credit Facility and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Junior DIP Facility.
The Senior DIP Credit Agreement and Junior DIP Credit Agreement both contained representations, warranties, covenants and events of default that are customary for DIP facilities of their type, including certain milestones applicable to the Chapter 11 Cases, compliance with an agreed budget, hedging on not less than 25% of our share of expected crude oil production for a specified period, and other customary limitations on additional indebtedness, liens, asset dispositions, investments, restricted payments and other negative covenants, in each case subject to exceptions.
Borrowings under the Senior DIP Facility bore interest at the London interbank offered rate (LIBOR) plus 4.5% for LIBOR loans and the alternative base rate (ABR) plus 3.5% for alternative base rate loans. We also agreed to pay an upfront fee equal to 1.0% on the commitment amount of the Senior DIP Facility and quarterly commitment fees of 0.5% on the undrawn portion of the Senior DIP Facility.
Borrowings under the Junior DIP Facility bore interest at a rate of LIBOR plus 9.0% for LIBOR loans and ABR plus 8.0% for alternate base rate loans. We also agreed to pay an upfront fee equal to 1.0% of the commitment amount funded on the closing date and a fronting fee to a fronting lender.
Certain of our subsidiaries, including each of the debtors in the Chapter 11 Cases, guaranteed all obligations under the Senior DIP Credit Agreement and Junior DIP Credit Agreement. We also granted liens on substantially all of our assets, whether now owned or hereafter acquired to secure the obligations under the Senior DIP Credit Agreement and Junior DIP Credit Agreement.
The Senior DIP Facility was repaid in full and terminated on the Effective Date using proceeds borrowed under our new Revolving Credit Facility discussed in Note 8 Debt. The Junior DIP Facility was also repaid in full and terminated on the Effective Date using (i) $200 million from the Second Lien Term Loan discussed below and (ii) $450 million from the Subscription Rights Offering discussed below.
Ares JV Settlement Agreement
On July 15, 2020, immediately prior to the commencement of the Chapter 11 Cases, we and certain affiliates of Ares Management L.P. (Ares), including ECR Corporate Holdings L.P., a portfolio company of Ares (ECR), entered into a Settlement and Assumption Agreement (Settlement Agreement) related to our midstream joint venture, Elk Hills Power, LLC (Ares JV or Elk Hills Power), which held our Elk Hills power plant and a cryogenic gas processing plant. On August 25, 2020, the Bankruptcy Court entered an order approving the Settlement Agreement on a final basis. Among other things, the Settlement Agreement included a conversion right, which was deemed exercised upon our emergence from bankruptcy, allowing us to acquire all (but not less than all) of the equity interests in the Ares JV held by ECR in exchange for secured notes (EHP Notes; see Note 8 Debt for additional information), approximately 20.8% of our new common stock (Ares Settlement Stock) and approximately $2 million in cash. For more information on the Settlement Agreement, see Note 7 Joint Ventures.
Rights Offering and Backstop
Pursuant to the Plan, we issued subscription rights to holders of our 2017 Credit Agreement, 2016 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes (Rights Offering). These subscription rights entitled holders to purchase up to $450 million of newly issued shares of common stock at $13 per share. Certain holders of our pre-emergence indebtedness agreed to backstop the Rights Offering and purchase additional shares in the event the Rights Offering was not fully subscribed in exchange for a premium. The Rights Offering closed on the Effective Date and we issued 38.1 million shares of common stock pursuant to the Rights Offering, including 3.5 million common shares issued to the backstop parties as a premium.
Emergence
The following transactions occurred on October 27, 2020, the effective date of the Plan, where we issued an aggregate of 83.3 million shares of new common stock, reserved 4.4 million shares for future issuance upon exercise of the warrants described below and reserved 9.3 million shares for future issuance under our management incentive plan, as described below:
•We acquired all of the member interests in the Ares JV held by ECR in exchange for the EHP Notes, 17.3 million shares of new common stock and approximately $2 million in cash (see Note 8 Debt and Note 7 Joint Ventures for additional information);
•Holders of secured claims under the 2017 Credit Agreement received 22.7 million shares of new common stock in exchange for those claims, and holders of deficiency claims under the 2017 Credit Agreement and all outstanding obligations under the 2016 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received 4.4 million shares of new common stock in exchange for those claims;
•In connection with the Subscription Rights and Backstop Commitment Agreement, 34.6 million shares of new common stock were issued in exchange for $446 million (net of a $4 million allocation adjustment credit paid to certain backstop parties), the gross proceeds of which were used to pay down our Junior DIP Facility;
•We issued 3.5 million shares as consideration for the backstop commitment premium; and
•We issued an aggregate of 821,000 shares to the lenders under our Junior DIP Facility as an exit fee.
The holders of Unsecured Debt Claims (as defined in the Plan) under the 2016 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received Tier 1 Warrants and Tier 2 Warrants (each as defined in the Plan and collectively, Warrants) to purchase up to 2% and 3%, respectively, of our outstanding shares (on a fully diluted basis calculated immediately after the Effective Date), with an initial exercise price of $36 per share, which expire on October 27, 2024 and have customary anti-dilution protections (refer to Note 15 Equity for additional information on the Warrants).
On January 18, 2021, our Board of Directors approved the California Resources Corporation 2021 Long Term Incentive Plan (2021 Incentive Plan). The shares issuable under the new long-term incentive plan had been previously authorized by the Bankruptcy Court in connection with our emergence from bankruptcy and the terms of the new long-term incentive plan were approved by our Board. As a result, the 2021 Incentive Plan became effective on January 18, 2021. The 2021 Incentive Plan provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, vested stock awards, dividend equivalents, other stock-based awards and substitute awards to employees, officers, non-employee directors and other service providers of the Company and its affiliates. In January 2021, we granted approximately 258,000 restricted stock units to our non-employee directors as the equity portion of their compensation. In addition, certain of our executives were granted approximately 544,000 restricted stock units and approximately 544,000 performance stock units.
All existing equity interests of the Predecessor, including contracts on equity, were cancelled and their holders received no recovery.
As a condition to our emergence, we repaid the outstanding balance of our debtor-in-possession financing with proceeds from our equity offering, Second Lien Term Loan and our new Revolving Credit Facility. For more information on our post-emergence indebtedness, see Note 8 Debt.
On October 27, 2020, all but one of our existing directors resigned and seven new non-employee directors were appointed to our Board of Directors (Board) in connection with our emergence from bankruptcy. In addition, our former Chief Executive Officer and director Todd A. Stevens departed on December 31, 2020. Our new Board is led by Mark A. (Mac) McFarland, our Chairman and interim Chief Executive Officer, and James N. Chapman, our Lead Independent Director.
Restructuring Charge
We reduced our workforce in August 2020 in response to economic conditions. In addition, our former Chief Financial Officer (CFO) departed on August 14, 2020 and former Chief Executive Officer (CEO) on December 31, 2020. In connection with these events, we recorded a charge to other expenses, net of $10 million in the Predecessor period and $5 million in the Successor period for post employment costs which primarily consisted of notice and severance pay. As of December 31, 2020, our remaining liability of $7 million was included in accrued liabilities. During 2019, we implemented operational efficiencies and an organizational redesign that included a reduction in our workforce. We recorded a related charge of $41 million, consisting of $29 million in notice and severance pay and $12 million in other termination benefits. As of December 31, 2019, our remaining liability of $19 million was included in accrued liabilities.
NOTE 3 FRESH START ACCOUNTING
Fresh Start Accounting
We adopted fresh start accounting upon emergence from bankruptcy 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.
For financial reporting purposes, fresh start accounting was applied as of October 31, 2020, an accounting convenience date, to coincide with the timing our normal month-end close process. We evaluated and concluded that events between October 28, 2020 and October 31, 2020 were not significant and the use of an accounting convenience date was appropriate.
Under fresh start accounting, the reorganization value of the emerging entity was assigned to individual assets and liabilities based on their estimated relative fair values. Reorganization value represents the fair value of our total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value was derived from our enterprise value, which was the estimated fair value of our long-term debt, asset retirement obligations and shareholder’s equity at emergence. In support of the Plan, our enterprise value was estimated and approved by the Bankruptcy Court to be in the range of $2.2 billion to $2.8 billion.
This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections, and applying standard valuation techniques, including net asset value analysis, precedent transactions analyses and comparable public company analyses. We engaged third-party valuation advisors to assist in determining the value of our Elk Hills power plant, cryogenic gas processing plant, certain real estate and warrants. Using these valuations along with our own internal estimates and assumptions for the value of our proved oil and natural gas reserves, we estimated our enterprise value to be $2.5 billion for financial reporting purposes.
The following is a summary of our valuation approaches and assumptions for significant non-current assets and liabilities, which excludes our working capital where our carrying value approximated fair value.
Property, Plant and Equipment
Our principal assets are our oil and natural gas properties. In valuing our proved oil and natural gas properties we used an income approach. Our estimated future revenue, operating costs and development plans were developed internally by our reserve engineers. We applied a discount rate using a market-participant weighted average cost of capital which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. We used a risk-adjusted discount rate for our proved undeveloped locations only. We estimated futures prices to calculate future revenue, as reported on the ICE Brent for oil and NGLs and NYMEX Henry Hub for natural gas as of October 31, 2020, adjusted for pricing differentials and without giving effect to derivative transactions. Operating costs and realized prices for periods after the forward price curve becomes illiquid were adjusted for inflation. No value was ascribed to unproved locations.
The fair value of our Elk Hills power plant, cryogenic gas processing facility (CGP-1) and commercial building in Bakersfield were estimated using a cost approach. The cost approach estimates fair value by considering the amount required to construct or purchase a new asset of equal utility at current prices, with adjustments for asset function, age, physical deterioration and obsolescence. We also considered the history of major capital expenditures.
We internally valued our surface acreage based on recent market data.
Right of Use Assets and Lease Liabilities
The fair value of right of use (ROU) assets and associated lease liabilities were measured at the present value of the remaining fixed minimum lease payments as if the leases were new leases at emergence. We used our incremental borrowing rate as the discount rate in determining the present value of the remaining lease payments. Based upon the corresponding lease term, our incremental borrowing rates ranged from 4% to 5%.
Pension and Postretirement Benefit Plans
The valuations of our pension liabilities and postretirement benefit obligations were performed by a third-party actuary. Valuation assumptions, including discount rates, expected future returns on plan assets, rates of future salary increases, rates of future increases in medical costs, turnover and mortality rates were developed in consultation with the third-party actuary based on current market conditions, current mortality rates and our expectation for future salary increases.
Long-term Debt Obligations
The fair value of our post-emergence long-term debt approximated carrying value based on the terms of the debt instruments and stated interest rates.
Asset Retirement Obligations
The fair value of our asset retirement obligations was estimated using a discounted cash flow approach for existing idle and currently producing wells and facilities. Our existing well population is approximately 18,000 individual well bores, on gross basis, and we estimated an average plugging and abandonment cost by field based on historical averages. We also factored in our testing plans related to idle well management and estimated failure rates to determine the timing of the cash flows. We utilized a credit adjusted risk free rate as our discount rate which was based on our credit rating and expected cost of borrowing at our emergence date. Our asset retirement obligations were reduced to our working interest share and factored in cost recovery related to our PSC-type contracts.
Warrants
The fair value of the warrants was estimated using a Black-Scholes model, a commonly used option pricing model. The Black-Scholes was used to estimate the fair value of our warrants with a stock price equal to book equity value per share, strike price, time to expiration, risk-free rate, equity volatility, which was based on a peer group of energy companies and dividend yield, which we estimated to be zero.
Reorganization Value
The following table summarizes our enterprise value upon emergence (in millions):
|
|
|
|
|
|
|
|
|
|
|
Fair value of total equity upon emergence
|
|
$
|
1,345
|
|
|
Fair value of long-term debt
|
|
725
|
|
|
Fair value of asset retirement obligations
|
|
593
|
|
|
Less: Unrestricted cash(a)
|
|
(163)
|
|
|
Total Enterprise Value
|
|
$
|
2,500
|
|
(a)Includes $118 million of cash used to temporarily collateralize letters of credit at our emergence date.
The following table reconciles our enterprise value to our reorganization value, or total asset value, upon emergence (in millions):
|
|
|
|
|
|
|
|
|
|
|
Enterprise value
|
|
$
|
2,500
|
|
|
Add: Unrestricted cash(a)
|
|
163
|
|
|
Add: Current liabilities(b)
|
|
396
|
|
|
Add: Other long-term liabilities(b)
|
|
231
|
|
|
Less: Other
|
|
(2)
|
|
|
Reorganization value
|
|
$
|
3,288
|
|
(a)Includes $118 million of cash used to temporarily collateralize letters of credit.
(b)Excludes asset retirement obligations of $50 million in current liabilities and $543 million in other long-term liabilities.
Consolidated Balance Sheet
The following consolidated balance sheet, with accompanying explanatory notes, illustrates the effects of the transactions contemplated by the Plan (Reorganization Adjustments) and fair value adjustments resulting from the adoption of fresh start accounting (Fresh Start Adjustments) as of October 31, 2020 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
Reorganization Adjustments
|
|
Fresh Start Adjustments
|
|
Successor
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
Cash
|
$
|
106
|
|
|
$
|
97
|
|
(1)
|
$
|
—
|
|
|
$
|
203
|
|
|
Trade receivables
|
149
|
|
|
—
|
|
|
—
|
|
|
149
|
|
|
Inventories
|
61
|
|
|
—
|
|
|
—
|
|
|
61
|
|
|
Other current assets, net
|
104
|
|
|
(2)
|
|
(2)
|
—
|
|
|
102
|
|
|
Total current assets
|
420
|
|
|
95
|
|
|
—
|
|
|
515
|
|
|
PROPERTY, PLANT AND EQUIPMENT
|
22,918
|
|
|
—
|
|
|
(20,236)
|
|
(12)
|
2,682
|
|
|
Accumulated depreciation, depletion and amortization
|
(18,588)
|
|
|
—
|
|
|
18,588
|
|
(12)
|
—
|
|
|
Total property, plant and equipment, net
|
4,330
|
|
|
—
|
|
|
(1,648)
|
|
|
2,682
|
|
|
OTHER ASSETS
|
77
|
|
|
18
|
|
(3)
|
(4)
|
|
(13)
|
91
|
|
|
TOTAL ASSETS
|
$
|
4,827
|
|
|
$
|
113
|
|
|
$
|
(1,652)
|
|
|
$
|
3,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
Reorganization Adjustments
|
|
Fresh Start Adjustments
|
|
Successor
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debtor-in-possession financing
|
733
|
|
|
(733)
|
|
(4)
|
—
|
|
|
—
|
|
|
Accounts payable
|
215
|
|
|
—
|
|
|
—
|
|
|
215
|
|
|
Accrued liabilities
|
233
|
|
|
(16)
|
|
(5)
|
14
|
|
(14)
|
231
|
|
|
Total current liabilities
|
1,181
|
|
|
(749)
|
|
|
14
|
|
|
446
|
|
|
LONG-TERM DEBT, NET
|
—
|
|
|
723
|
|
(6)
|
—
|
|
|
723
|
|
|
OTHER LONG-TERM LIABILITIES
|
725
|
|
|
—
|
|
|
49
|
|
(15)
|
774
|
|
|
LIABILITIES SUBJECT TO COMPROMISE
|
4,516
|
|
|
(4,516)
|
|
(7)
|
—
|
|
|
—
|
|
|
MEZZANINE EQUITY
|
|
|
|
|
|
|
|
|
Redeemable noncontrolling interests
|
691
|
|
|
(691)
|
|
(8)
|
—
|
|
|
—
|
|
|
EQUITY
|
|
|
|
|
|
|
|
|
Predecessor preferred stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Predecessor common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Predecessor additional paid-in capital
|
5,149
|
|
|
(5,149)
|
|
(9)
|
—
|
|
|
—
|
|
|
Successor preferred stock
|
—
|
|
|
|
|
—
|
|
|
—
|
|
|
Successor common stock
|
—
|
|
|
1
|
|
(10)
|
—
|
|
|
1
|
|
|
Successor additional paid-in capital
|
—
|
|
|
1,253
|
|
(10)
|
—
|
|
|
1,253
|
|
|
Successor warrants
|
—
|
|
|
15
|
|
(10)
|
—
|
|
|
15
|
|
|
Accumulated deficit
|
(7,481)
|
|
|
9,226
|
|
(11)
|
(1,745)
|
|
(16)
|
—
|
|
|
Accumulated other comprehensive loss
|
(23)
|
|
|
—
|
|
|
23
|
|
(17)
|
—
|
|
|
Total equity attributable to common stock
|
(2,355)
|
|
|
5,346
|
|
|
(1,722)
|
|
|
1,269
|
|
|
Equity attributable to noncontrolling interests
|
69
|
|
|
—
|
|
|
7
|
|
(18)
|
76
|
|
|
Total equity
|
(2,286)
|
|
|
5,346
|
|
|
(1,715)
|
|
|
1,345
|
|
|
TOTAL LIABILITIES AND EQUITY
|
$
|
4,827
|
|
|
$
|
113
|
|
|
$
|
(1,652)
|
|
|
$
|
3,288
|
|
Reorganization Adjustments
(1)Net change in cash upon our emergence included the following transactions (in millions):
|
|
|
|
|
|
|
|
Proceeds from Revolving Credit Facility
|
$
|
225
|
|
|
Proceeds from Subscription Rights and Backstop Commitment, net
|
446
|
|
|
Proceeds from Second Lien Term Loan
|
200
|
|
|
Repayment of debtor-in-possession facilities
|
(733)
|
|
|
Payment of legal, professional and other fees
|
(15)
|
|
|
Debt issuance costs for the Revolving Credit Facility
|
(18)
|
|
|
Debt issuance costs for the Second Lien Term Loan
|
(2)
|
|
|
Acquisition of noncontrolling interest as part of the Settlement Agreement
|
(2)
|
|
|
Distribution to noncontrolling interest holder
|
(3)
|
|
|
Payment of accrued interest and bank fees
|
(1)
|
|
|
Net change
|
$
|
97
|
|
Our cash balance of $203 million at October 31, 2020 included $158 million of restricted cash, of which $118 million was used to temporarily collateralize letters of credit, $22 million was held for distributions to a JV partner and $18 million was reserved for legal and professional fees related to our Chapter 11 Cases.
(2)Represents the write-off of unamortized insurance premiums for our directors and officers policy, which was cancelled as a result of changing the composition of our Board of Directors.
(3)Represents the capitalization of debt issuance costs for our Revolving Credit Facility.
(4)Represents the payoff of $733 million of debtor-in-possession financing including $83 million of borrowings that were outstanding under our Senior DIP Facility and $650 million of borrowings that were outstanding under our Junior DIP Facility. Refer to Note 2 Chapter 11 Proceedings for more information on our debtor-in-possession credit agreements.
(5)Reflects the payment of $15 million for legal, professional and other fees related to our bankruptcy proceedings upon emergence and $1 million for accrued interest and bank fees.
(6)Our exit financing at emergence included the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 31, 2020
|
|
|
|
|
|
|
|
|
($ in millions)
|
|
|
|
|
|
|
Revolving Credit Facility
|
$
|
225
|
|
|
|
|
|
|
|
|
Second Lien Term Loan
|
200
|
|
|
|
|
|
|
|
|
EHP Notes
|
300
|
|
|
|
|
|
|
|
|
Long-term debt (principal amount)
|
$
|
725
|
|
|
|
|
|
|
|
|
Debt issuance costs
|
(2)
|
|
|
|
|
|
|
|
|
Total long-term debt, net
|
$
|
723
|
|
|
|
|
|
|
|
For additional information on our Successor debt, refer to Note 8 Debt.
(7)Our liabilities subject to compromise at emergence included the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (principal amount):
|
|
|
|
2017 Credit Agreement
|
|
$
|
1,300
|
|
|
2016 Credit Agreement
|
|
1,000
|
|
|
Second Lien Notes
|
|
1,808
|
|
|
5.5% Senior Notes due 2021
|
|
100
|
|
|
6% Senior Notes due 2024
|
|
144
|
|
|
Accrued interest
|
|
164
|
|
|
Total liabilities subject to compromise
|
|
$
|
4,516
|
|
(8)Represents the acquisition of the noncontrolling interest in our Ares JV. In accordance with the Settlement Agreement, we exercised a conversion right upon our emergence from bankruptcy, allowing us to acquire all (but not less than all) of the equity interests in the Ares JV held by ECR in exchange for the EHP Notes, Ares Settlement Stock and approximately $2 million in cash.
(9)Represents the elimination of Predecessor additional paid-in capital.
(10) Represents the fair value of 83.3 million shares of Successor common stock and Warrants issued in accordance with the Plan as follows (in millions):
|
|
|
|
|
|
|
|
Par value
|
$
|
1
|
|
|
Additional paid-in capital
|
1,253
|
|
|
Warrants
|
15
|
|
|
Total
|
$
|
1,269
|
|
(11) Represents the decrease in accumulated deficit resulting from reorganization adjustments and the reclassification from Predecessor additional paid-in capital.
Fresh Start Adjustments
(12) Represents fair value adjustments to property, plant and equipment (PP&E), including the elimination of Predecessor accumulated depreciation, depletion and amortization.
The fair value of our PP&E at emergence consisted of the following:
|
|
|
|
|
|
|
|
Proved oil and natural gas properties
|
$
|
2,409
|
|
|
Facilities and other
|
273
|
|
|
Total PP&E
|
$
|
2,682
|
|
(13) Represents an adjustment to our right of use assets as if our lease agreements were new leases on our emergence date. See Note 9 Leases for more information on our leases.
(14) Represents a $20 million fair value adjustment to the current portion of asset retirement obligations partially offset by a $5 million decrease in our liability for self-insured medical. Also included are fair value adjustments for our postretirement benefits and a remeasurement of the current portion of our lease liability.
(15) Represents a $36 million fair value adjustment related to the long-term portion of asset retirement obligations and $8 million related to environmental and other abandonment obligations. The adjustment also includes $5 million related to remeasuring our long-term lease liability as if our contracts were new leases.
(16) Represents the elimination of Predecessor accumulated deficit.
(17) Represents the elimination of Predecessor accumulated other comprehensive loss.
(18) Represents a fair value adjustment of the noncontrolling interest in the BSP JV based on discounted expected future cash flows.
NOTE 4 ACCOUNTING AND DISCLOSURE CHANGES
Recently Adopted Accounting and Disclosure Changes
We adopted new accounting guidance on current expected credit losses on January 1, 2020, using a modified retrospective approach to the first period in which the guidance was effective. The new rules changed the measurement of credit losses for financial assets and certain other instruments, including trade and other receivables with a right to receive cash, and require the use of a new forward-looking expected loss model that results in the earlier recognition of an allowance for losses. The adoption of these new rules did not have a significant impact on our consolidated financial statements.
We adopted the Financial Accounting Standards Board's new lease accounting rules (ASC 842), as of January 1, 2019, using the modified retrospective approach where the new lease standard is not applied to prior comparative periods, which continue to be presented under accounting standards in effect for those prior periods. The adoption of the new lease accounting rules did not materially impact our consolidated results of operations and had no impact on cash flows or beginning retained earnings.
NOTE 5 PROPERTY, PLANT AND EQUIPMENT
In connection with the application of fresh start accounting, as discussed in Note 3 Fresh Start Accounting, we recorded our PP&E at fair value as of our emergence date. Predecessor accumulated depreciation, depletion and amortization was therefore eliminated as of that date.
We capitalize the costs incurred to acquire or develop our oil and natural gas assets, including ARO and capitalized interest. For asset acquisitions, purchase price, including liabilities assumed, is allocated to acquired assets based on relative fair values at the acquisition date.
We evaluate long-lived assets on a quarterly basis for possible impairment. We recorded a $1.7 billion impairment charge in the first quarter of 2020 for our proved and unproved oil and natural gas properties.
Property, plant and equipment, net consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
(in millions)
|
December 31, 2020
|
|
|
December 31, 2019
|
|
Proved oil and natural gas properties
|
$
|
2,416
|
|
|
|
$
|
21,285
|
|
|
Unproved oil and natural gas properties(a)
|
1
|
|
|
|
1,055
|
|
|
Facilities and other
|
272
|
|
|
|
549
|
|
|
Total property, plant and equipment
|
2,689
|
|
|
|
22,889
|
|
|
Accumulated depreciation, depletion and amortization
|
(34)
|
|
|
|
(16,537)
|
|
|
Total property, plant and equipment, net
|
$
|
2,655
|
|
|
|
$
|
6,352
|
|
(a)Includes a valuation allowance for unproved properties of zero and $823 million at December 31, 2020 and 2019, respectively.
The following table summarizes the activity of capitalized exploratory well costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
Years ended
December 31,
|
|
(in millions)
|
|
|
|
2019
|
|
2018
|
|
Beginning balance
|
$
|
3
|
|
|
|
$
|
7
|
|
|
$
|
5
|
|
|
$
|
4
|
|
|
Additions to capitalized exploratory well costs
|
—
|
|
|
|
—
|
|
|
12
|
|
|
19
|
|
|
Reclassification to property, plant and equipment
|
—
|
|
|
|
—
|
|
|
(3)
|
|
|
(2)
|
|
|
Charged to expense
|
—
|
|
|
|
(2)
|
|
|
(7)
|
|
|
(16)
|
|
|
Impact of fresh start accounting
|
—
|
|
|
|
(2)
|
|
|
—
|
|
|
—
|
|
|
Ending balance
|
$
|
3
|
|
|
|
$
|
3
|
|
|
$
|
7
|
|
|
$
|
5
|
|
There are not significant exploratory well costs in the periods presented that have been capitalized for a period greater than one year after the completion of drilling. In response to the commodity price environment, in the first quarter of 2020, we suspended our drilling program which continued throughout the remainder of 2020. Our capitalized exploratory well costs at December 31, 2020 are for permitted wells that we intend to drill.
See Note 13 Asset Impairment for more information on our first quarter impairment charge and Note 3 Fresh Start Accounting for more information on fair value adjustments.
NOTE 6 DIVESTITURES AND ACQUISITIONS
Divestitures
Lost Hills Divestiture
In May 2019, we sold 50% of our working interest and transferred operatorship in certain zones within our Lost Hills field, located in the San Joaquin basin, for total consideration in excess of $200 million, consisting of approximately $168 million in cash and a carried 200-well development program to be drilled through 2023 with an estimated value of $35 million (Lost Hills divestiture). We received cash proceeds of $164 million after transaction costs and purchase price adjustments, which were used to pay down our 2014 Revolving Credit Facility. The partial sale of proved property was accounted for as a normal retirement with no gain or loss recognized. The partial sale of unproved property was recorded as a recovery of cost.
Other
In January 2020, we sold royalty interests and divested non-core assets resulting in $41 million of proceeds which was treated as a normal retirement and no gain or loss was recognized. In 2018, we divested non-core assets resulting in $18 million of proceeds and recognized a $5 million gain.
Acquisitions
Elk Hills Transaction
In April 2018, we acquired the remaining working, surface and mineral interests in the approximately 47,000-acre Elk Hills unit from Chevron U.S.A., Inc. (Chevron) (the Elk Hills transaction) for approximately $518 million, including $7 million of liabilities assumed relating to ARO. We accounted for the Elk Hills transaction as a business combination. As of December 31, 2019, we held all of the working, surface and mineral interests in the former Elk Hills unit. The effective date of the transaction was April 1, 2018.
As part of the Elk Hills transaction, Chevron reduced its royalty interest in one of our oil and natural gas properties by half and extended the time frame to invest the remainder of our capital commitment on that property by the end of 2022. As of December 31, 2020, the remaining commitment was approximately $12 million. In addition, the parties mutually agreed to release each other from pending claims with respect to the former Elk Hills unit.
Bakersfield Office Building
In April 2018, we also acquired an office building and land in Bakersfield, California for $48 million.
Other
In 2019, we had several other acquisitions totaling approximately $6 million. In 2018, we had other upstream acquisitions totaling approximately $39 million, excluding assumed ARO liabilities of $1 million.
NOTE 7 JOINT VENTURES
Noncontrolling Interests
The following tables present the changes in noncontrolling interests for our consolidated JVs (described in greater detail below), which are reported in equity and mezzanine equity on our consolidated balance sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Attributable to Noncontrolling Interests
|
|
Mezzanine Equity - Redeemable Noncontrolling Interest
|
|
|
Ares JV
|
|
BSP JV
|
|
Total
|
|
Ares JV
|
|
|
|
Total
|
|
|
(in millions)
|
|
Balance, December 31, 2018 (Predecessor)
|
$
|
15
|
|
|
$
|
99
|
|
|
$
|
114
|
|
|
$
|
756
|
|
|
|
|
$
|
756
|
|
|
Net (loss) income attributable to noncontrolling interests
|
(7)
|
|
|
17
|
|
|
10
|
|
|
117
|
|
|
|
|
117
|
|
|
Contributions from noncontrolling interest holders, net
|
—
|
|
|
49
|
|
|
49
|
|
|
—
|
|
|
|
|
—
|
|
|
Distributions to noncontrolling interest holders
|
(8)
|
|
|
(72)
|
|
|
(80)
|
|
|
(71)
|
|
|
|
|
(71)
|
|
|
Balance, December 31, 2019 (Predecessor)
|
$
|
—
|
|
|
$
|
93
|
|
|
$
|
93
|
|
|
$
|
802
|
|
|
|
|
$
|
802
|
|
|
Net income (loss) attributable to noncontrolling interests
|
3
|
|
|
10
|
|
|
13
|
|
|
94
|
|
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to noncontrolling interest holders
|
(3)
|
|
|
(34)
|
|
|
(37)
|
|
|
(67)
|
|
|
|
|
(67)
|
|
|
Modification of noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
(138)
|
|
|
|
|
(138)
|
|
|
Acquisition of noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
(691)
|
|
|
|
|
(691)
|
|
|
Impact of fresh start accounting
|
—
|
|
|
7
|
|
|
7
|
|
|
—
|
|
|
|
|
—
|
|
|
Balance, October 31, 2020 (Predecessor)
|
$
|
—
|
|
|
$
|
76
|
|
|
$
|
76
|
|
|
$
|
—
|
|
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Attributable to Noncontrolling Interest
|
|
|
|
|
|
BSP JV
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
Balance, October 31, 2020 (Successor)
|
|
$
|
76
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to noncontrolling interests
|
|
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to noncontrolling interest holders
|
|
(30)
|
|
|
|
|
|
|
|
|
Balance, December 31, 2020 (Successor)
|
|
$
|
44
|
|
|
|
|
|
|
|
Ares JV
In February 2018, our wholly-owned subsidiary California Resources Elk Hills, LLC (CREH) entered into a midstream JV with ECR, a portfolio company of Ares, with respect to the Elk Hills power plant (a 550-megawatt natural gas fired power plant) and a 200 MMcf/day cryogenic gas processing plant. These assets were held by the joint venture entity, Elk Hills Power, LLC (Elk Hills Power), and each of CREH and ECR held an equity interest in this entity.
On the Effective Date, our wholly-owned subsidiary, EHP Midco Holding Company, LLC (Elk Hills Issuer) entered into a Note Purchase Agreement (Note Purchase Agreement) with certain subsidiaries of Ares and Wilmington Trust, N.A. as collateral agent. As required by the Note Purchase Agreement, CREH transferred its ownership of two low temperature separation plants located at the Elk Hills field to Elk Hills Power.
Prior to our Effective Date, we held 50% of the Class A common interest and 95.25% of the Class C common interest in the Ares JV. ECR held 50% of the Class A common interest, 100% of the Class B preferred interest and 4.75% of the Class C common interest. The Ares JV was required to distribute each month its excess cash flow over its working capital requirements first to the Class B holders and then to the Class C common interests, on a pro-rata basis. As contemplated by the terms of the JV, CREH purchased electricity and gas processing services from the Ares JV (subject to certain limitations, including certain geographical limitations) in exchange for monthly capacity payments pursuant to the terms of a Commercial Agreement, the proceeds of which were used by the Ares JV to make distributions as contemplated by the Second Amended and Restated Limited Liability Company Agreement of Elk Hills Power, LLC. CREH also served as the operator of the Ares JV and provided operational and support services in exchange for a monthly fee pursuant to a Master Services Agreement. These agreements became intercompany agreements on the Effective Date and were cancelled as described below.
As described in Note 2 Chapter 11 Proceedings, we entered into the Settlement Agreement with ECR and Ares which, among other things, granted us the right (Conversion Right) to acquire all (but not less than all) of the equity interests of Elk Hills Power owned by ECR in exchange for the EHP Notes, Ares Settlement Stock and approximately $2 million in cash. The Conversion Right was exercised on the Effective Date.
Although certain provisions in the Settlement Agreement were not effective until certain conditions were met, such as the Bankruptcy Court entering a final order, we determined that the amended terms were substantively different such that the existing Class A common, Class B preferred and Class C common member interests held by ECR were treated as redeemed in exchange for new member interests issued at fair value in the third quarter of 2020. The estimated fair value of the new member interests was lower than the carrying value of the existing member interests by $138 million. In accordance with GAAP, the modification of noncontrolling interest was recorded to additional paid-in capital and was included in our earnings per share calculations. See Note 16 Earnings per Share for adjustments to net income (loss) attributable to common stock which includes a modification of noncontrolling interest.
We exercised the Conversion Right on the Effective Date and issued the EHP Notes in the aggregate principal amount of $300 million, Ares Settlement Stock comprising approximately 20.8% (subject to dilution) of common stock and approximately $2 million in cash (Conversion). Upon the Conversion, Elk Hills Power became our indirect wholly-owned subsidiary, and Ares and its affiliates ceased to have any direct or indirect interest in Elk Hills Power. In connection with the Conversion, Elk Hills Power’s limited liability company agreement was amended and restated.
In connection with the Conversion, on the Effective Date, we entered into a Sponsor Support Agreement dated the Effective Date (Support Agreement) pursuant to which, among other things, the parties agreed that Elk Hills Power will be our primary provider of electricity to, and will be the primary processor of our natural gas produced from, the Elk Hills field, which is already consistent with our current practice.
On the Effective Date, in connection with the Conversion, we terminated: (a) the Commercial Agreement, dated as of February 7, 2018, by and between Elk Hills Power and CREH and (b) the Master Services Agreement, dated as of February 7, 2018, by and between Elk Hills Power and CREH.
Our consolidated statements of operations for the Predecessor periods reflect the operations of the Ares JV, with ECR's share of net income (loss) reported in net income attributable to noncontrolling interests. Distributions to ECR reduce the carrying amount of noncontrolling interests on our consolidated balance sheets and are reported as a financing cash outflow on our consolidated statements of cash flows. ECR's redeemable noncontrolling interests was reported in mezzanine equity due to an embedded optional redemption feature.
BSP JV
In February 2017, we entered into a development joint venture with Benefit Street Partners (BSP) where BSP invested $200 million to date, before transaction costs, in exchange for a preferred interest in the BSP JV. BSP is entitled to preferential distributions and, if it receives cash distributions equal to a predetermined threshold, the preferred interest is automatically redeemed in full with no additional payment. The funds contributed by BSP were used to develop certain of our oil and natural gas properties.
The BSP JV holds net profits interests (NPI) in existing and future cash flow from certain of our properties and the proceeds from the NPI are used by the BSP JV to (1) pay quarterly minimum distributions to BSP, (2) make distributions to BSP until the predetermined threshold is achieved, and (3) pay for additional development costs within the project area, upon mutual agreement between members.
Our consolidated results reflect the operations of our development JV with BSP, with BSP's preferred interest reported in equity on our consolidated balance sheets and BSP’s share of net income (loss) reported in net income attributable to noncontrolling interests in our consolidated statements of operations for all periods presented. Distributions to BSP reduce the carrying amount of noncontrolling interests on our consolidated balance sheets and are reported as a financing cash outflow on our consolidated statements of cash flows.
Other
Alpine JV
In July 2019, we entered into a development joint venture with Alpine Energy Capital, LLC (Alpine) to develop portions of our Elk Hills field (Alpine JV). Alpine is a joint venture between subsidiaries of Colony Capital, Inc. (Colony) and Equity Group Investments. Alpine committed to invest an initial $320 million in the Elk Hills field of which $226 million has been invested to date. The initial commitment was expected to be invested over a period of up to three years in accordance with a 275-well development plan. Alpine will fund 100% of the drilling and completion costs of these wells, in which they will earn a 90% working interest. If Alpine receives an agreed upon return, our working interest in those wells will increase from 10% to 82.5%. Our consolidated financial statements reflect only our working interest share in the productive wells.
On March 27, 2020, Alpine elected to suspend its funding obligations pursuant to a contractual right that was triggered when the average NYMEX 12-month forward strip price for Brent crude oil fell below $45 per barrel over a 30-trading day period. The suspension may be lifted by mutual consent. As of December 31, 2020, funding for the initial development phase has not re-started.
In connection with the Alpine JV, we issued a warrant to purchase up to 1.25 million shares of our Predecessor common stock at an exercise price of $40 per share. On the Effective Date, this warrant was cancelled, pursuant to the Plan.
MIRA JV
In April 2017, we entered into a development joint venture with Macquarie Infrastructure and Real Assets Inc. (MIRA) to develop certain of our oil and natural gas properties in the San Joaquin basin in exchange for a 90% working interest in the related properties (MIRA JV). MIRA funded 100% of the drilling and completion costs of wells in the agreed-upon drilling program. Our 10% working interest increases to 75% if MIRA receives cash distributions equal to a predetermined threshold return. The initial phase of the agreed-upon drilling program was funded through December 31, 2020. Our consolidated results reflect only our working interest share in the productive wells.
Royale JV
In October 2018, we entered into a three-year development joint venture for a 30-well program with Royale Energy, Inc. (Royale) where Royale committed approximately $23 million for natural gas development in Sacramento Valley, of which $8 million has been funded to date. We committed to investing approximately $13 million, of which $4 million has been funded to date. In June 2020, we entered into an amendment with Royale which postponed the start dates of the second- and third-year drilling programs by one year. Our consolidated results reflect our 40% working interest share of production from these wells.
NOTE 8 DEBT
In January 2021, we completed a private placement of $600 million in senior unsecured notes due 2026 (Senior Notes). The net proceeds of $590 million were used to repay in full our Second Lien Term Loan and EHP Notes, with the remainder used to repay a portion of the outstanding borrowings under our Revolving Credit Facility. The Senior Notes will be guaranteed on a senior unsecured basis by certain of our material subsidiaries. See Note 19 Subsequent Events for additional information on this offering.
Post-Emergence Indebtedness
As of December 31, 2020, our long-term debt consisted of the following credit agreements, Second Lien Notes and Senior Notes (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
Interest Rate(a)
|
|
Maturity
|
|
|
2020
|
|
|
|
|
|
Credit Agreements
|
|
|
|
|
|
|
Revolving Credit Facility
|
$
|
99
|
|
|
LIBOR plus 3%-4%
ABR plus 2%-3%
|
|
April 29, 2024
|
|
Second Lien Notes
|
|
|
|
|
|
|
Second Lien Term Loan
|
200
|
|
|
LIBOR plus 9%-10.5%
ABR plus 8%-9.5%
|
|
October 27, 2025
|
|
Senior Notes
|
|
|
|
|
|
|
EHP Notes
|
300
|
|
|
6%
|
|
October 27, 2027
|
|
Long-term debt (principal amount)
|
$
|
599
|
|
|
|
|
|
|
Unamortized debt issuance costs
|
(2)
|
|
|
|
|
|
|
Total long-term debt, net
|
$
|
597
|
|
|
|
|
|
(a)London Interbank Offered Rates (LIBOR) will be phased out after 2021 and replaced with the Secured Overnight Financing Rate within the United States for U.S. dollar-based LIBOR. Our credit agreements contemplate a discontinuation of LIBOR and have an alternate borrowing rate. We do not expect the discontinuation of LIBOR to have a significant impact on our interest expense.
Revolving Credit Facility
On October 27, 2020, we entered into a Credit Agreement with Citibank, N.A., as administrative agent, and certain other lenders. This credit agreement currently consists of a $540 million senior revolving loan facility (Revolving Credit Facility), which we are permitted to increase if we obtain additional commitments from new or existing lenders. The aggregate revolving commitment is subject to an automatic reduction if additional commitments from new lenders are not obtained. As a result, we expect the aggregate commitment of our lenders will be reduced to $492 million in April 2021. Our Revolving Credit Facility also includes a sub-limit of $200 million for the issuance of letters of credit. As of December 31, 2020, we had approximately $307 million available for borrowing under the Revolving Credit Facility after taking into account $134 million of outstanding letters of credit.
On the Effective Date, we borrowed $225 million under the Revolving Credit Facility to refinance our DIP Facilities, replace our existing letters of credit and pay certain costs, fees and expenses related to the other transactions consummated on the Effective Date. Our initial borrowings included $118 million used to cash collateralize on an interim basis certain letters of credit that were outstanding under our Senior DIP Facility. These letters of credit were transitioned into our new Revolving Credit Facility at December 31, 2020. The proceeds of all or a portion of the Revolving Credit Facility may be used for our working capital needs and for other purposes subject to meeting certain criteria.
Security – The lenders have a first-priority lien on a substantial majority of our assets, except assets securing the EHP Notes as discussed below.
Interest Rate – We can elect to borrow at either an adjusted LIBOR rate or an ABR rate, subject to a 1% floor and 2% floor, respectively, plus an applicable margin. The ABR is equal to the highest of (i) the federal funds effective rate plus 0.50%, (ii) the administrative agent prime rate and (iii) the one-month adjusted LIBOR rate plus 1%. The applicable margin is adjusted based on the borrowing base utilization percentage and will vary from (i) in the case of LIBOR loans, 3% to 4% and (ii) in the case of ABR loans, 2% to 3%; provided that in the event that the EHP Notes are not paid in full on or prior to December 31, 2021, the applicable margin will be increased by 0.25% effective as of January 1, 2022 and will be increased by an additional 0.25% at the beginning of each subsequent fiscal quarter until such date on which the EHP Notes are paid in full. The unused portion of the facility is subject to a commitment fee of 0.50% per annum. We also pay customary fees and expenses. Interest on ABR loans is payable quarterly in arrears. Interest on LIBOR loans is payable at the end of each LIBOR period, but not less than quarterly.
Maturity Date – Our Revolving Credit Facility matures on April 29, 2024.
Amortization Payments – The Revolving Credit Facility does not include any obligation to make amortizing payments.
Borrowing Base – The borrowing base, currently $1.2 billion, will be redetermined semi-annually each April and October.
Financial Covenants – Our Revolving Credit Facility includes the following financial covenants:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ratio
|
|
Components
|
|
Required Levels
|
|
Tested
|
|
Consolidated Total Net Leverage Ratio
|
|
Ratio of consolidated total secured debt to consolidated EBITDAX(a)
|
|
Not greater than 3.00 to 1.00
|
|
Quarterly
|
|
Current Ratio
|
|
Ratio of consolidated current assets to consolidated current liabilities(b)
|
|
Not less than 1.00 to 1.00
|
|
Quarterly
|
(a)EBITDAX is calculated as defined in the credit agreement.
(b)The available credit under our Revolving Credit Facility is included in consolidated current assets as part of the calculation of the current ratio.
Other Covenants – Our Revolving Credit Facility includes covenants that, among other things, restrict our ability to incur additional indebtedness, grant liens, make asset sales and investments, repay existing indebtedness, make subsidiary distributions and enter into transactions that would result in fundamental changes. We are also restricted in the amount of cash dividends we can pay on our common stock unless we meet certain covenants included in the credit agreement.
Our Revolving Credit Facility also requires us to maintain hedges on a minimum amount of crude oil production, determined semi-annually, of no less than (i) 75% of our reasonably anticipated oil production from our proved reserves for the first 24 months after the closing of the Revolving Credit Facility, which occurred on the Effective Date, and (ii) 50% of our reasonably anticipated oil production from our proved reserves for a period from the 25th month through the 36th month after the same date. The Revolving Credit Facility specifies the forms of hedges and prices (which can be prevailing prices) that must be used for a portion of those hedges.
We must also maintain acceptable commodity hedges for no less than 50% of the reasonably anticipated oil production from our proved reserves for at least 24 months following the date of delivery of each reserve report. We may not hedge more than 80% of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids from our oil and gas properties for a 48-month period.
Events of Default and Change of Control – Our Revolving Credit Facility provides for certain events of default, including upon a change of control, as defined in the credit agreement, that entitles our lenders to declare the outstanding loans immediately due and payable, subject to certain limitations and conditions.
Second Lien Term Loan
On October 27, 2020, we entered into a $200 million credit agreement with Alter Domus Products Corp., as administrative agent, and certain other lenders (Second Lien Term Loan). The proceeds were used to refinance our Junior DIP Facility and to pay certain costs, fees and expenses related to the other transactions consummated on the Effective Date.
Security – The lenders had a second-priority lien (junior to the Revolving Credit Facility) on a substantial majority of our assets, except assets securing the EHP Notes as discussed below.
Interest Rate – We could elect to pay interest at either an adjusted LIBOR rate or ABR rate, subject to a 1% floor and 2% floor, respectively, plus an applicable margin. The ABR rate was equal to the highest of (i) the prime rate, (ii) the federal funds rate effective rate plus 0.50%, and (iii) the one-month adjusted LIBOR rate plus 1%. Prior to the second anniversary of the closing date of the Second Lien Term Loan, the applicable margin in the case of an ABR rate election was 8% per annum if paid in cash and 9.50% per annum if paid-in-kind, and the applicable margin in the case of an adjusted LIBOR rate election was 9% if paid in cash and 10.50% if paid-in-kind. After the second anniversary of the closing date, the applicable margin was 8% with respect to any ABR loan and 9% with respect to an adjusted LIBOR loan. Interest on ABR loans was paid quarterly in arrears and interest based on the adjusted LIBOR rate was due at the end of each LIBOR period, which could be one, two, three or six months but not less than quarterly. We also paid customary fees and expenses.
Maturity Date – Our Second Lien Term Loan would mature five years after the closing date, subject to extension.
Redemption – We could elect to redeem all or part of our Second Lien Term Loan, at any time prior to the maturity date, at redemption price equal to (i) 100% of the principal amount if redeemed prior to 90 days after closing, (ii) 105% of the principal amount if redeemed after 90 days and before the first anniversary date, (iii) 103% of the principal amount if redeemed on or after the first anniversary date and before the second anniversary date, (iv) 102% of the principal amount if redeemed on or after the second anniversary date and before the third anniversary date, (v) 101% of the principal amount if redeemed on or after the third anniversary date and before the fourth anniversary date, and (vi) at 100% of the principal amount if redeemed in the fifth year.
Financial Covenants – Our Second Lien Term Loan included certain financial covenants that were to be tested quarterly, including a consolidated total net leverage ratio and current ratio.
Liquidity – We would become subject to a monthly minimum liquidity requirement of $170 million if, as of the Spring 2021 Scheduled Redetermination (as defined in the Revolving Credit Facility), (a) our liquidity was less than $247 million and (b) we were not able to obtain at least $51 million in additional commitments under our Revolving Credit Facility or through capital markets or other junior financing transactions, for so long as the conditions in (a) and (b) remained unmet.
Other Covenants – Our Second Lien Term Loan included covenants that, among other things, restricted our ability to incur additional indebtedness, grant liens, make asset sales and investments, repay existing indebtedness, make subsidiary distributions and enter into transactions that would result in fundamental changes. We were also restricted in the amount of cash dividends we could pay on our common stock unless we met certain covenants included in the credit agreement.
Our Second Lien Term Loan also required us to maintain hedges on a minimum amount of crude oil production on terms that were substantially consistent with the requirements of our Revolving Credit facility.
Events of Default and Change of Control – Our Second Lien Term Loan provided for certain events of default, including upon a change of control, as defined in the credit agreement, that would entitle our lenders to declare the outstanding loans immediately due and payable, subject to certain limitations and conditions. We were subject to a cross-default provision that causes a default under this facility if certain defaults occurred under the Revolving Credit Facility or the EHP Notes.
The Second Lien Term Loan was terminated and repaid with proceeds from our Senior Notes offering in January 2021 as described in Note 19 Subsequent Events.
EHP Notes
On the Effective Date, our wholly-owned subsidiary, EHP Midco Holding Company, LLC (Elk Hills Issuer) entered into a Note Purchase Agreement (Note Purchase Agreement) with certain subsidiaries of Ares and Wilmington Trust, N.A. as collateral agent. The $300 million Notes were issued as partial consideration for the Class B Preferred Units, Class A Common Units and Class C Common Units in the Ares JV previously held by ECR (EHP Notes).
The EHP Notes were senior notes due in 2027, and were secured by a first-priority security interest in all of the assets of Elk Hills Power, any third-party offtake contracts for power generated by Elk Hills Power, all of the equity interests of Elk Hills Power held by Elk Hills Issuer and all of the equity interests of Elk Hills Issuer held by its direct parent, EHP Topco Holding Company, LLC, our wholly-owned subsidiary. We and Elk Hills Power guaranteed, on a joint and several basis, all of the obligations of Elk Hills Issuer under the EHP Notes. The EHP Notes bore an interest rate of 6.0% per annum through the fourth anniversary of issuance, increasing to 7.0% per annum after the fourth anniversary of issuance and to 8.0% per annum after the fifth anniversary of issuance. We were permitted to redeem the EHP Notes at any time prior to their maturity date without payment of premium or penalty.
The EHP Notes were terminated and repaid with proceeds from our Senior Notes offering in January 2021 as described in Note 19 Subsequent Events.
Pre-Emergence Indebtedness
2014 Revolving Credit Facility
In September 2014, we entered into a Credit Agreement with JPMorgan Chase Bank, N.A, as administrative agent, and certain other lenders. This credit agreement consisted of a $1 billion senior revolving loan facility (2014 Revolving Credit Facility), which we were permitted to increase by up to $50 million if we obtain additional commitments from new or existing lenders and also included a sub-limit of $400 million for the issuance of letters of credit. Prior to our Chapter 11 Cases in 2020, we amended our the 2014 Revolving Credit Facility to reduce our credit facility to $900 million and our borrowing base was reduced to $1.2 billion.
Amounts outstanding under the 2014 Revolving Credit Facility bore interest at either LIBOR or an alternate base rate (ABR), in each case plus an applicable margin. The applicable margin was adjusted based on the borrowing base utilization percentage under the 2014 Revolving Credit Facility and could vary from (i) in the case of LIBOR loans, 3.25% to 4.00% and (ii) in the case of ABR loans, 2.25% to 3.00%. The unused portion of the facility is subject to a commitment fee of 0.50% per annum. We also paid customary fees and expenses.
The lenders shared a first-priority lien on a substantial majority of our assets with the lenders under of 2017 Credit Agreement, excluding the Elk Hills power plant and midstream assets that are part of the Ares JV. The maturity date of our 2014 Revolving Credit Facility was June 30, 2021.
Under the 2014 Revolving Credit Facility, we were subject to various financial covenants including a monthly liquidity requirement and quarterly tests including maximum leverage ratio, minimum interest coverage ratio and minimum asset coverage ratio. Our 2014 Revolving Credit Facility also included covenants that, among other things, restricted our ability to incur additional indebtedness, grant liens, make asset sales and investments, repay existing indebtedness, make subsidiary distributions and enter into transactions that would result in fundamental changes. We were also restricted from paying cash dividends on our stock.
The 2014 Revolving Credit Facility was terminated and repaid with proceeds from the Senior DIP Facility and Junior DIP Facility.
2017 Credit Agreement
In November 2017, we entered into a $1.3 billion credit agreement with The Bank of New York Mellon Trust Company, N.A., as administrative agent, and certain other lenders (2017 Credit Agreement). Our 2017 Credit Agreement is secured by the same shared first-priority lien used to secure our 2014 Revolving Credit Facility. The maturity date of the loans was December 31, 2022, subject to a springing maturity of 91 days prior to the maturity of our 2016 Credit Agreement if more than $100 million is outstanding at that time.
We were required to maintain a first-lien asset coverage ratio of not less than 1.20 to 1.00 as of any June 30 and December 31. In addition, our 2017 Credit Agreement provided for customary covenants and events of default consistent with, or generally less restrictive than, the covenants in our 2014 Revolving Credit Facility. The covenants included limitations on additional indebtedness, liens, asset dispositions and investments, among others, and were in each case subject to certain limitations and exceptions. We were also restricted from paying cash dividends on our stock.
The 2017 Credit Agreement was cancelled upon our emergence from bankruptcy as described in Note 2 Chapter 11 Proceedings.
2016 Credit Agreement
In August 2016, we entered into a $1 billion credit agreement with The Bank of New York Mellon Trust Company, N.A., as administrative agent, and certain other lenders (2016 Credit Agreement). Our 2016 Credit Agreement was secured by a first-priority lien on a substantial majority of our assets (excluding the Elk Hills power plant and midstream assets that are part of the Ares JV) but was second in collateral recovery to our 2014 Revolving Credit Facility and 2017 Credit Agreement. The maturity date of the 2016 Credit Agreement was December 31, 2021.
We were required to maintain a first–lien asset coverage ratio of not less than 1.20 to 1.00 as of any June 30 and December 31. Our 2016 Credit Agreement also included other covenants that are substantially similar to our 2017 Credit Agreement. We were also restricted from paying cash dividends on our stock.
The 2016 Credit Agreement was cancelled upon our emergence from bankruptcy as described in Note 2 Chapter 11 Proceedings.
Second Lien Notes
In December 2015, we issued $2.25 billion in aggregate principal amount of 8% senior secured second-lien notes due December 15, 2022 (Second Lien Notes). The Second Lien Notes were issued in exchange for $2.8 billion of our then outstanding Senior Notes. We recorded a deferred gain of approximately $560 million on the debt exchange, which was being amortized using the effective yield method over the term of our Second Lien Notes.
Our Second Lien Notes were secured on a junior-priority basis to the first-priority liens that secure the loans under our 2014 Revolving Credit Facility, 2017 Credit Agreement and 2016 Credit Agreement. The indenture included covenants that, among other things, limited our ability to grant liens securing borrowed money (subject to certain exceptions) and restricted our ability to merge or consolidate with, or transfer all or substantially all of our assets to, another entity.
In the first quarter of 2020, we repurchased $7 million in face value of our Second Lien Notes for $3 million in cash, resulting in a pre-tax gain of $5 million including the effect of unamortized deferred gain and issuance costs. In 2019, we repurchased $252 million in face value of our Second Lien Notes for $156 million in cash, resulting in a pre-tax gain of $126 million including the effect of unamortized deferred gain and issuance costs.
The Second Lien Notes were cancelled upon our emergence from bankruptcy as described in Note 2 Chapter 11 Proceedings.
Senior Notes
In October 2014, we issued $5 billion in aggregate principal amount of our senior unsecured notes, including $1 billion of 5% notes due January 15, 2020 (2020 Notes), $1.75 billion of 5.5% notes due September 15, 2021 (2021 Notes) and $2.25 billion of 6% notes due November 15, 2024 (2024 Notes and, collectively, Senior Notes). We used the net proceeds from the issuance of our Senior Notes to make a $4.95 billion cash distribution to Occidental in October 2014.
The indenture included covenants that, among other things, limited our ability to grant liens securing borrowed money subject to certain exceptions and restrict our ability to merge or consolidate with, or transfer all or substantially all of our assets to, another entity.
The Senior Notes were cancelled upon our emergence from bankruptcy as described in Note 2 Chapter 11 Proceedings.
Other
At December 31, 2020, all obligations under our Revolving Credit Facility and Second Lien Term Loan are guaranteed by certain of our material wholly owned subsidiaries.
The terms and conditions of all of our indebtedness are subject to additional qualifications and limitations that are set forth in the relevant governing documents.
At December 31, 2020, we were in compliance with all debt covenants under our credit agreements.
Principal maturities of debt outstanding at December 31, 2020 (Successor) are as follows:
|
|
|
|
|
|
|
|
|
As of
December 31, 2020
|
|
|
(in millions)
|
|
2021
|
$
|
—
|
|
|
2022
|
—
|
|
|
2023
|
—
|
|
|
2024
|
99
|
|
|
2025
|
200
|
|
|
Thereafter
|
300
|
|
|
Total
|
$
|
599
|
|
We estimate the fair value of fixed-rate debt, which is classified as Level 3, based on unobservable inputs as of December 31, 2020. We estimate the fair value of fixed-rate debt, which is classified as Level 1, based on prices known from market transactions as of December 31, 2019. The estimated fair value of our debt at December 31, 2020 and 2019, including the fair value of the variable-rate portion, was approximately $599 million and $3.8 billion, respectively, compared to a face value of approximately $599 million and $5.0 billion, respectively.
NOTE 9 LEASES
We lease commercial office space, fleet vehicles, drilling rigs and facilities. We do not recognize acquired leases or leases with an initial term of 12 months or less on the balance sheet. Upon adoption of fresh start accounting, our right of use (ROU) assets and lease liabilities were recorded at the present value of the remaining fixed minimum lease payments as if the leases were new leases upon our emergence date. The effect of fresh start accounting on leases was not material. Refer to Note 3 Fresh Start Accounting for more details.
Balance sheet information related to our operating and finance leases as of December 31, 2020 and December 31, 2019 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Classification
|
|
2020
|
|
|
2019
|
|
Assets
|
|
|
(in millions)
|
|
|
(in millions)
|
|
Operating
|
Other assets
|
|
$
|
38
|
|
|
|
$
|
59
|
|
|
Finance
|
PP&E
|
|
1
|
|
|
|
2
|
|
|
Total leased assets
|
|
|
$
|
39
|
|
|
|
$
|
61
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
Operating
|
Accrued liabilities
|
|
$
|
6
|
|
|
|
$
|
27
|
|
|
Finance
|
Accrued liabilities
|
|
1
|
|
|
|
1
|
|
|
Long-term
|
|
|
|
|
|
|
|
Operating
|
Other long-term liabilities
|
|
35
|
|
|
|
37
|
|
|
Finance
|
Other long-term liabilities
|
|
—
|
|
|
|
1
|
|
|
Total lease liabilities
|
|
|
$
|
42
|
|
|
|
$
|
66
|
|
In considering whether a contract contains a lease, we first considered whether there was an identifiable asset and then considered how and for what purpose the asset would be used over the contract term. Our lease liability was determined by measuring the present value of the remaining fixed minimum lease payments discounted using our incremental borrowing rate (IBR). In determining our IBR, we considered the average cost of borrowing for publicly traded corporate bond yields, which were adjusted to reflect our credit rating, the remaining lease term for each class of our leases and frequency of payments.
We combine lease and nonlease components in determining fixed minimum lease payments for our drilling rigs and commercial office space. If applicable, fixed minimum lease payments are reduced by lease incentives for our commercial buildings and increased by mobilization and demobilization fees for our drilling rigs. Certain of our lease agreements include options to renew, which we exercise at our sole discretion, and we did not include these options in determining our fixed minimum lease payments over the lease term. Our lease liability does not include options to extend or terminate our leases. Our leases do not include options to purchase the leased property. Lease agreements for our fleet vehicles include residual value guarantees, none of which are recognized in our financial statements until the underlying contingency is resolved.
Variable lease costs for our drilling rigs include costs to operate, move and repair the rigs. Variable lease costs for certain of our commercial office buildings included utilities and common area maintenance charges. Variable lease costs for our fleet vehicles included other-than-routine maintenance and other various amounts in excess of our fixed minimum rental fee.
Our lease costs, including amounts capitalized to PP&E, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
January 1, 2019 - December 31, 2019
|
|
|
(in millions)
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating lease costs
|
$
|
2
|
|
|
|
$
|
23
|
|
|
$
|
52
|
|
|
Short-term lease costs(a)
|
7
|
|
|
|
25
|
|
|
74
|
|
|
Variable lease costs(b)
|
—
|
|
|
|
4
|
|
|
21
|
|
|
Total operating lease costs
|
9
|
|
|
|
52
|
|
|
147
|
|
|
Finance lease costs
|
—
|
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
Sublease income
|
$
|
—
|
|
|
|
$
|
(1)
|
|
|
$
|
(1)
|
|
|
Total lease costs
|
$
|
9
|
|
|
|
$
|
52
|
|
|
$
|
146
|
|
(a)Contracts with terms of less than one month or less are excluded from our disclosure of short-term lease costs.
(b)No variable lease costs related to drilling rigs in the Successor period. The Predecessor period of January 1, 2020 through October 31, 2020 includes $3 million related to drilling rigs and 2019 includes $19 million, which were capitalized to PP&E.
We have two contracts treated as finance leases, which were not material to our consolidated results of operations.
We sublease certain commercial office space to third parties where we are the primary obligor under the head lease. The lease terms on those subleases never extend past the term of the head lease and the subleases contain no extension options or residual value guarantees. Sublease income is recognized based on the contract terms and included as a reduction of operating lease cost under our head lease. Sublease income was not material to our consolidated financial statements for all periods presented.
Other supplemental information related to our operating and finance leases as of December 31, 2020 and December 31, 2019 is provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
January 1, 2019 - December 31, 2019
|
|
|
(in millions)
|
|
|
(in millions)
|
|
Cash paid for amounts included in the measurement of lease liabilities
|
|
|
|
|
|
|
|
Operating cash outflows from operating leases
|
$
|
2
|
|
|
|
$
|
9
|
|
|
$
|
14
|
|
|
Investing cash outflows from operating leases
|
$
|
—
|
|
|
|
$
|
14
|
|
|
$
|
40
|
|
|
Financing cash outflows from finance leases
|
$
|
—
|
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
ROU assets obtained in exchange for new operating lease liabilities
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
122
|
|
|
ROU assets obtained in exchange for new finance lease liabilities
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
Impairment charges related to ROU assets
|
$
|
—
|
|
|
|
$
|
2
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
2020
|
|
|
2019
|
|
Operating Leases
|
|
|
|
|
|
Weighted-average remaining lease term (in years)
|
6.81
|
|
|
4.75
|
|
Weighted-average discount rate
|
4.5
|
%
|
|
|
12.2
|
%
|
|
|
|
|
|
|
|
Finance Leases
|
|
|
|
|
|
Weighted-average remaining lease term (in years)
|
1.33
|
|
|
2.33
|
|
Weighted-average discount rate
|
4.0
|
%
|
|
|
8.5
|
%
|
The difference in the weighted-average discount rate between operating leases and finance leases primarily relates to lease term.
As part of our company-wide consolidation of office space, we vacated certain office space in 2020 and 2019, some of which we subleased. When we enter into a sublease agreement, we evaluate the carrying value of our ROU asset (including the carrying value of related tenant improvements) for impairment based on future identifiable cash flows. We may terminate leases for vacated office space before the expiration of the lease term. In cases where we decided not to sublease vacated commercial office space, we shorten the useful life of the ROU assets and related tenant improvements to recover our remaining costs over our expected period of use.
Maturities of our operating and finance lease liabilities at December 31, 2020 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Operating
|
|
Finance
|
|
|
Leases
|
|
Leases
|
|
|
(in millions)
|
|
2021
|
$
|
8
|
|
|
$
|
1
|
|
|
2022
|
8
|
|
|
—
|
|
|
2023
|
7
|
|
|
—
|
|
|
2024
|
6
|
|
|
—
|
|
|
2025
|
5
|
|
|
—
|
|
|
Thereafter
|
15
|
|
|
—
|
|
|
Less: Interest
|
(7)
|
|
|
—
|
|
|
Present value of lease liabilities
|
$
|
42
|
|
|
$
|
1
|
|
NOTE 10 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES
We, or certain of our subsidiaries, are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at December 31, 2020 and 2019 were not material to our consolidated balance sheets as of such dates.
In October 2020, Signal Hill Services, Inc. defaulted on its decommissioning obligations associated with two offshore platforms. The Bureau of Safety and Environmental Enforcement determined that former lessees, including our former parent, Occidental Petroleum Corporation (Oxy) with an approximately 35% share, are responsible for accrued decommissioning obligations associated with these offshore platforms. Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy. We are currently evaluating this claim.
We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined.
We have certain commitments under contracts, including purchase commitments for goods and services used in the normal course of business such as pipeline capacity, land easements and field equipment. At December 31, 2020, total purchase obligations on a discounted basis were as follows:
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
|
(in millions)
|
|
2021
|
$
|
42
|
|
|
2022
|
50
|
|
|
2023
|
35
|
|
|
2024
|
6
|
|
|
2025
|
6
|
|
|
Thereafter
|
47
|
|
|
Total
|
186
|
|
|
Less: Interest
|
(28)
|
|
|
Present value of purchase obligations
|
$
|
158
|
|
We remain subject to audit by the Internal Revenue Service for calendar years 2017 through 2019 as well as 2016 through 2019 by the state of California.
NOTE 11 DERIVATIVES
We continue to maintain a commodity hedging program primarily focused on crude oil to help protect our cash flows, margins and capital program from the volatility of commodity prices. Our Revolving Credit Facility and Second Lien Term Loan require that we hedge a significant amount of crude oil production as described in Note 8 Debt. We have met our hedging obligation under our Revolving Credit Facility and Second Lien Term Loan.
Commodity-Price Risk
We did not have any commodity derivatives designated as accounting hedges as of and during the years ended December 31, 2020, 2019 and 2018. As part of our hedging program, we held the following Brent-based crude oil contracts as of December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1
2021
|
|
Q2
2021
|
|
Q3
2021
|
|
Q4
2021
|
|
2022
|
|
January - October 2023
|
|
|
|
Sold Calls:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels per day
|
19,028
|
|
|
33,372
|
|
|
35,202
|
|
|
10,645
|
|
|
30,783
|
|
|
17,758
|
|
|
|
|
Weighted-average price per barrel
|
$
|
47.88
|
|
|
$
|
48.64
|
|
|
$
|
49.83
|
|
|
$
|
56.00
|
|
|
$
|
59.37
|
|
|
$
|
58.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Puts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels per day
|
39,148
|
|
|
37,872
|
|
|
36,617
|
|
|
35,483
|
|
|
30,783
|
|
|
17,758
|
|
|
|
|
Weighted-average price per barrel
|
$
|
41.88
|
|
|
$
|
40.00
|
|
|
$
|
40.00
|
|
|
$
|
40.00
|
|
|
$
|
40.00
|
|
|
$
|
40.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sold Puts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels per day
|
15,659
|
|
|
15,149
|
|
|
14,647
|
|
|
14,193
|
|
|
3,042
|
|
|
—
|
|
|
|
|
Weighted-average price per barrel
|
$
|
35.97
|
|
|
$
|
31.41
|
|
|
$
|
30.00
|
|
|
$
|
32.00
|
|
|
$
|
32.00
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels per day
|
7,830
|
|
|
7,574
|
|
|
7,323
|
|
|
7,097
|
|
|
6,576
|
|
|
5,919
|
|
|
|
|
Weighted-average price per barrel
|
$
|
43.74
|
|
|
$
|
44.13
|
|
|
$
|
43.82
|
|
|
$
|
45.30
|
|
|
$
|
46.29
|
|
|
$
|
47.57
|
|
|
|
The BSP JV holds crude oil derivatives and natural gas swaps for insignificant volumes through 2021 that are included in our consolidated results. The hedges entered into by the BSP JV could affect the timing of the redemption of BSP's preferred interest.
The outcomes of the derivative positions are as follows:
•Sold call options – we make settlement payments for prices above the indicated weighted-average price per barrel.
•Purchased put options – we receive settlement payments for prices below the indicated weighted-average price per barrel.
•Sold put options – we make settlement payments for prices below the indicated weighted-average price per barrel.
•Swaps – we make settlement payments for prices above the indicated weighted-average price per barrel and receive settlement payments for prices below the indicated weighted-average price per barrel.
From time to time, we may use combinations of these positions to increase the efficacy of our hedging program.
We mark our derivative contracts to market at the end of each reporting period. These noncash derivative gains and losses, along with settlement payments, are reported in net derivative (loss) gain from commodity contracts on our consolidated statements of operations as shown in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
Year ended
December 31, 2019
|
|
Year ended
December 31, 2018
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
Non-cash derivative (loss) gain
|
$
|
(140)
|
|
|
|
$
|
(17)
|
|
|
$
|
(170)
|
|
|
$
|
229
|
|
|
Net (payments) proceeds on settled commodity derivatives
|
(1)
|
|
|
|
108
|
|
|
111
|
|
|
(228)
|
|
|
Net derivative (loss) gain from commodity contracts
|
$
|
(141)
|
|
|
|
$
|
91
|
|
|
$
|
(59)
|
|
|
$
|
1
|
|
Interest-Rate Risk
In May 2018, we entered into derivative contracts that limit our interest rate exposure with respect to $1.3 billion of our variable-rate indebtedness. These interest-rate contracts reset monthly and require the counterparties to pay any excess interest owed on such amount in the event the one-month LIBOR exceeds 2.75% for any monthly period prior to May 4, 2021.
For the Successor and Predecessor periods in 2020, we did not report gains or losses on these contracts. For the year ended December 31, 2019, we reported a loss on these contracts, included in other non-operating expenses on our consolidated statement of operations, of $4 million. No payments from these contracts were received in either 2020 or 2019.
Fair Value of Derivatives
Our derivative contracts are measured at fair value using industry-standard models with various inputs, including quoted forward prices, and are classified as Level 2 in the required fair value hierarchy for the periods presented.
Commodity Contracts
The following tables present the fair values (at gross and net) of our outstanding derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020 (Successor)
|
|
Classification
|
|
Gross Amounts at Fair Value
|
|
Netting
|
|
Net Fair Value
|
|
Assets:
|
|
(in millions)
|
|
Other current assets
|
|
$
|
21
|
|
|
$
|
(21)
|
|
|
$
|
—
|
|
|
Other assets
|
|
63
|
|
|
(63)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
Accrued liabilities
|
|
(71)
|
|
|
21
|
|
|
(50)
|
|
|
Other long-term liabilities
|
|
(69)
|
|
|
63
|
|
|
(6)
|
|
|
|
|
$
|
(56)
|
|
|
$
|
—
|
|
|
$
|
(56)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019 (Predecessor)
|
|
Classification
|
|
Gross Amounts at Fair Value
|
|
Netting
|
|
Net Fair Value
|
|
Assets:
|
|
(in millions)
|
|
Other current assets
|
|
$
|
49
|
|
|
$
|
(10)
|
|
|
$
|
39
|
|
|
Other assets
|
|
1
|
|
|
—
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
Accrued liabilities
|
|
(15)
|
|
|
10
|
|
|
(5)
|
|
|
Other long-term liabilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
$
|
35
|
|
|
$
|
—
|
|
|
$
|
35
|
|
Interest-Rate Contracts
The fair value of our interest-rate derivatives contracts was not significant for all periods presented.
Counterparty Credit Risk
As of December 31, 2020, all of our derivative financial instruments were with investment-grade counterparties. We believe exposure to credit-related losses at December 31, 2020 was not material and losses associated with credit risk have been insignificant for all years presented.
All of our derivative instruments are covered by International Swap Dealers Association Master Agreements
with counterparties. At December 31, 2020, and 2019, we had insignificant collateral posted.
NOTE 12 INCOME TAXES
Income Tax Provision (Benefit)
Net (loss) income before income taxes, for all periods presented, was generated from domestic operations. We did not record a significant income tax provision (benefit) in any of the periods presented, due to our valuation allowance.
Total income tax provision (benefit) differs from the amounts computed by applying the U.S. federal income tax rate to pre-tax income (loss) as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
Years ended
December 31,
|
|
|
|
|
|
2019
|
|
2018
|
|
U.S. federal statutory tax rate
|
(21)
|
%
|
|
|
21
|
%
|
|
21
|
%
|
|
21
|
%
|
|
State income taxes, net
|
(7)
|
|
|
|
7
|
|
|
7
|
|
|
6
|
|
|
Exclusion of income attributable to noncontrolling interests, net
|
—
|
|
|
|
(1)
|
|
|
(35)
|
|
|
(5)
|
|
|
Debt restructuring, net
|
—
|
|
|
|
(8)
|
|
|
—
|
|
|
—
|
|
|
Changes in tax attributes, net
|
—
|
|
|
|
7
|
|
|
(9)
|
|
|
(6)
|
|
|
Nondeductible compensation, net
|
—
|
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
Change in valuation allowance, net
|
27
|
|
|
|
(27)
|
|
|
14
|
|
|
(17)
|
|
|
Other, net
|
1
|
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
Effective tax rate
|
—
|
%
|
|
|
—
|
%
|
|
1
|
%
|
|
—
|
%
|
Our effective tax rate is primarily affected by state taxes, income included in our consolidated results which is taxed to noncontrolling interests, and the benefit of tax credits, when available. Further, as a result of our emergence from bankruptcy, we wrote-off deferred tax assets because of the limitation on the realizability of our net operating loss and tax carryforwards as described further below. Given our income tax position, any item affecting our effective tax rate is generally offset by an equal change in the valuation allowance.
In connection with our emergence from bankruptcy and cancellation of claims, which were included in liabilities subject to compromise as of our emergence date, we generated cancellation of debt income for tax purposes which was excluded from taxable income under rules related to bankruptcy proceedings. In exchange for this exclusion, for federal purposes, we were required to reduce our net operating loss (NOL) and tax credit carryforwards and the tax basis of our assets, primarily property, plant and equipment. The primary driver of the income tax benefit related to the cancellation of our debt is due to the mechanics of attribute reduction for state combined income tax reporting purposes.
Our ability to utilize our remaining NOL, tax credit and interest expense carryforwards may be limited since we experienced an “ownership change” in connection with the restructuring process. Absent an applicable exception, if a corporation undergoes an ownership change, the amount of its NOLs and other carryforwards that may be used to reduce U.S. federal and state income tax obligations is subject to an annual limitation. Although an exception to the imposition of an annual limitation applies in Chapter 11 Cases under Section 382(l)(5) of the Internal Revenue Code of 1986, as amended, it is currently not likely if we will apply such section because if we experience a subsequent ownership change within two years of the Effective Date, any remaining net operating losses and certain other tax attributes, including interest expense carryforwards, may be subject to further and more severe limitations. Accordingly, the write-off of the benefit for our remaining NOLs and other carryforwards had the effect of increasing our effective tax rate in the Predecessor period.
Deferred Tax Assets and Liabilities
The tax effects of temporary differences resulting in deferred income tax assets and liabilities at December 31, 2020 and 2019 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
2020
|
|
|
2019
|
|
(in millions)
|
Deferred Tax
Assets
|
|
Deferred Tax
Liabilities
|
|
|
Deferred Tax
Assets
|
|
Deferred Tax
Liabilities
|
|
Debt
|
$
|
3
|
|
|
$
|
—
|
|
|
|
$
|
176
|
|
|
$
|
—
|
|
|
Property, plant and equipment
|
209
|
|
|
(113)
|
|
|
|
—
|
|
|
(517)
|
|
|
Postretirement benefit accruals
|
43
|
|
|
—
|
|
|
|
40
|
|
|
—
|
|
|
Deferred compensation and benefits
|
23
|
|
|
—
|
|
|
|
55
|
|
|
—
|
|
|
Asset retirement obligations
|
178
|
|
|
—
|
|
|
|
155
|
|
|
—
|
|
|
Net operating loss and tax credit carryforwards
|
12
|
|
|
—
|
|
|
|
457
|
|
|
—
|
|
|
Business interest expense carryforward
|
180
|
|
|
—
|
|
|
|
194
|
|
|
—
|
|
|
Investment in partnerships
|
—
|
|
|
—
|
|
|
|
110
|
|
|
—
|
|
|
Other
|
34
|
|
|
(20)
|
|
|
|
36
|
|
|
(60)
|
|
|
Subtotal
|
682
|
|
|
(133)
|
|
|
|
1,223
|
|
|
(577)
|
|
|
Valuation allowance
|
(549)
|
|
|
—
|
|
|
|
(646)
|
|
|
—
|
|
|
Total deferred taxes
|
$
|
133
|
|
|
$
|
(133)
|
|
|
|
$
|
577
|
|
|
$
|
(577)
|
|
Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit use of existing deferred tax assets. A significant piece of evidence evaluated is a history of operating losses. Such evidence limits our ability to consider other evidence such as projections for growth. As of December 31, 2020, we concluded that we could not realize, on a more-likely-than-not basis, any of our deferred tax assets and there is not sufficient evidence to support the reversal of all or any portion of this allowance. Given our recent and anticipated future earnings trends, we do not believe any significant amount of the valuation allowance as of December 31, 2020 will be released within the next 12 months. Changes in assumptions could materially affect the recognized amounts of valuation allowance.
Other
As of December 31, 2020, we had U.S. federal net operating loss carryforwards of $17 million, which begin to expire in 2039. Our carryforward for business interest expense of $855 million does not expire.
As of December 31, 2020, we had California net operating loss carryforwards of approximately $2 billion, which begin to expire in 2026, and an insignificant amount of tax credit carryforwards.
Unrecognized Tax Benefits
We did not record a liability for unrecognized tax benefits in the Successor period. The following is a reconciliation of unrecognized tax benefits in the Predecessor period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
|
January 1, 2020 - October 31, 2020
|
|
Years ended
December 31,
|
|
(in millions)
|
|
|
|
2019
|
|
2018
|
|
Unrecognized tax benefits – beginning balance
|
|
|
|
$
|
101
|
|
|
$
|
25
|
|
|
$
|
25
|
|
|
Gross (decreases) increases – tax positions in prior year
|
|
|
|
(101)
|
|
|
44
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross increases – tax positions in current year
|
|
|
|
—
|
|
|
32
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized tax benefits – ending balance
|
|
|
|
$
|
—
|
|
|
$
|
101
|
|
|
$
|
25
|
|
On July 28, 2020 the Internal Revenue Service (IRS) issued final regulations which clarified the calculation of the limitation on the deduction of business interest expense. Based on our evaluation of these final regulations, we determined that our income tax returns were filed at least on a more-likely-than-not basis and accordingly we reversed a $76 million liability for uncertain tax positions. Further, we re-evaluated a tax return filing position taken in prior periods and reversed a $25 million liability for uncertain tax positions.
NOTE 13 ASSET IMPAIRMENT
At March 31, 2020, we recorded a $1.7 billion impairment charge which was triggered by the sharp drop in commodity prices at the end of the first quarter of 2020 due to the significant decrease in demand for oil and natural gas products as a result of the Coronavirus Disease 2019 (COVID-19) pandemic coupled with the over-supply resulting from a price war between members of the Organization of the Petroleum Exporting Countries (OPEC) and Russia and other allied producing countries. The following table presents a summary of our asset impairments as of our March 31, 2020 assessment date (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and natural gas properties
|
$
|
1,487
|
|
|
Unproved properties
|
228
|
|
|
Other
|
21
|
|
|
Total
|
$
|
1,736
|
|
Proved oil and natural gas properties — The fair values of our proved oil and natural gas properties were determined as of the date of the assessment using discounted cash flow models incorporating a number of fair value inputs which are categorized as Level 3 on the fair value hierarchy. These inputs were based on management's expectations for the future considering the then-current environment and included index prices based on forward curves, pricing adjustments for differentials, estimates of future oil and natural gas production, estimated future operating costs and capital development plans based on the embedded price assumptions. We used a market-based weighted average cost of capital to discount the future net cash flows. The impairment charge primarily related to a steamflood property located in the San Joaquin basin.
Unproved properties — As of our assessment date, we determined our ability to develop our unproved properties, which primarily consisted of leases held by production in the San Joaquin basin, was constrained for the foreseeable future and we did not intend to develop them.
NOTE 14 STOCK-BASED COMPENSATION
As a result of our bankruptcy, the outstanding stock-based awards under our Amended and Restated California Resources Corporation Long-Term Incentive Plan (Amended LTIP) were cancelled on our Effective Date.
On January 18, 2021, our Board of Directors approved the California Resources Corporation 2021 Long Term Incentive Plan (2021 Incentive Plan). The shares issuable under the new long-term incentive plan had been previously authorized by the Bankruptcy Court in connection with our emergence from Chapter 11 and the terms of the new long-term incentive plan were approved by our Board of Directors. As a result, the 2021 Incentive Plan became effective on January 18, 2021. The 2021 Incentive Plan provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, vested stock awards, dividend equivalents, other stock-based awards and substitute awards to employees, officers, non-employee directors and other service providers of the Company and its affiliates. The 2021 Incentive Plan provides for the reservation of 9,257,740 shares of common stock for future issuances, subject to adjustment as provided in the 2021 Incentive Plan. Shares of stock subject to an award under the 2021 Incentive Plan that expires or is cancelled, forfeited, exchanged, settled in cash or otherwise terminated without the actual delivery of shares (restricted stock awards are not considered “delivered shares” for this purpose) will again be available for new awards under the 2021 Incentive Plan. However, (i) shares tendered or withheld in payment of any exercise or purchase price of an award or taxes relating to awards, (ii) shares that were subject to an option or a stock appreciation right but were not issued or delivered as a result of the net settlement or net exercise of the option or stock appreciation right, and (iii) shares repurchased on the open market with the proceeds from the exercise price of an option, will not, in each case, again be available for new awards under the 2021 Incentive Plan.
In January 2021 we granted approximately 258,000 restricted stock units to our non-employee directors as the equity portion of their compensation. In addition, certain of our executives were granted approximately 544,000 restricted stock units and 544,000 performance stock units.
Predecessor Compensation Plan
In 2019, our stockholders approved the Amended LTIP, which provided for the issuance of stock, incentive and non-qualified stock options, restricted stock awards, restricted stock units, stock appreciation rights, stock bonuses, performance-based awards and other awards to executives, employees and non-employee directors. Shares of our common stock were permitted to be withheld by us in satisfaction of tax withholding obligations arising upon the exercise of stock options or the vesting of restricted stock units. Further, shares of our common stock were permitted to be withheld by us in payment of the exercise price of employee stock options, which also counted against the authorized shares specified above.
The maximum number of authorized shares of our common stock that were available for issuance pursuant to the Amended LTIP was 7.3 million shares. As of December 31, 2019, 4.7 million shares were issued or reserved under the Amended LTIP and 2.6 million shares were available for future issuance of awards. In the second quarter of 2020, our then Board of Directors approved the following changes to the 2020 compensation program: (i) the previously established target amounts under the 2020 variable compensation programs remained unchanged, but any unvested amounts under such programs were revised to only be eligible for cash settlement, and (ii) as a condition to receiving any award under our 2020 variable compensation programs, participants waived participation in our 2020 annual incentive program and forfeited all stock-based compensation awards previously granted in 2020. At the time of the amendments, there were no changes to any stock-based compensation awards granted prior to February 2020; however, as a result of our bankruptcy, the outstanding stock-based awards under our Amended LTIP were cancelled on our Effective Date.
The cancellation of the stock-based compensation awards granted under the Amended LTIP prior to 2020 resulted in the recognition of all previously unrecognized compensation expense for equity-based awards under the Amended LTIP and the elimination of the liability related to cash-based awards under the Amended LTIP.
As shown in the table below, we recognized the following stock-based compensation expense during the Predecessor periods. No stock-based compensation was recognized during the Successor period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
|
January 1, 2020 - October 31, 2020
|
|
Years ended
December 31,
|
|
(in millions)
|
|
|
|
2019
|
|
2018
|
|
Stock-based compensation expense
|
|
|
|
$
|
3
|
|
|
$
|
32
|
|
|
$
|
45
|
|
|
Payments of cash-based portion of awards
|
|
|
|
$
|
8
|
|
|
$
|
25
|
|
|
$
|
24
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock Units
As part of the Amended LTIP, executives and other employees were granted restricted stock units (RSUs). RSUs were service based and, depending on the terms of the awards, were settled in cash or stock at the time of vesting. The awards either (i) vested ratably over three years, with one third of the granted units becoming vested on the day before each of the first three anniversaries of the applicable date of grant, or (ii) cliff vested upon the third anniversary of the applicable date of grant. Our RSUs had nonforfeitable dividend rights, and any dividends or dividend equivalents declared during the vesting period were paid as declared.
For cash- and stock-settled RSUs, compensation value was initially measured on the date of grant using the quoted market price of our common stock. Compensation expense for cash-settled RSUs was adjusted on a monthly basis for the cumulative change in the value of the underlying stock. Compensation expense for the stock-settled RSUs were recognized on a straight-line basis over the requisite service periods, adjusted for actual forfeitures. All outstanding RSUs were cancelled for no consideration as a result of our emergence from bankruptcy.
The following summarizes our RSU activity for 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-Settled
|
|
Cash-Settled
|
|
|
Number of Units
|
|
Weighted-Average Grant-Date Fair Value
|
|
Number of Units
|
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
Unvested at December 31, 2019 (Predecessor)
|
554
|
|
|
$
|
17.54
|
|
|
2,285
|
|
|
Granted
|
633
|
|
|
$
|
6.20
|
|
|
4,327
|
|
|
Vested
|
(357)
|
|
|
$
|
16.40
|
|
|
(1,062)
|
|
|
Cancelled or Forfeited
|
(830)
|
|
|
$
|
9.37
|
|
|
(5,550)
|
|
|
|
|
|
|
|
|
|
Unvested at October 31, 2020 (Predecessor)
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
Performance Stock Units
Our performance stock units (PSUs) were restricted stock unit awards with performance targets with payouts ranging from 0% to 200% of the target award. Up to the target amount of the PSUs were eligible to be settled in cash or stock, and any amount of the PSUs earned in excess of the target amounts of such PSUs were to be settled in cash. These awards accrued dividend equivalents as dividends are declared during the vesting period, which were paid upon certification for the number of earned PSUs. Compensation expense was adjusted quarterly, on a cumulative basis, for any changes in the number of share equivalents expected to be paid based on the relevant performance criteria. All outstanding PSUs were cancelled for no consideration as a result of our emergence from bankruptcy.
The following summarizes our PSU activity for 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-Settled
|
|
Cash-Settled
|
|
|
|
|
Number of Awards
|
|
Weighted-Average Grant-Date Fair Value
|
|
Number of Units
|
|
|
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
|
Unvested at December 31, 2019 (Predecessor)
|
497
|
|
|
$
|
19.75
|
|
|
401
|
|
|
|
|
Granted
|
792
|
|
|
$
|
6.20
|
|
|
792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cancelled or Forfeited
|
(1,289)
|
|
|
$
|
11.43
|
|
|
(1,193)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested at October 31, 2020 (Predecessor)
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options
We granted stock options to certain executives under our Amended LTIP. These options permitted the purchase of Predecessor common stock at exercise prices no less than the fair market value of the stock on the date the options were granted, with the majority of options being granted at 10% above fair market value. The options had terms of seven years and vested ratably over three years, with one third of the granted options becoming exercisable on the day before each of the first three anniversaries of the applicable date of grant, subject to certain restrictions including continued employment. All outstanding stock options were cancelled for no consideration as a result of our emergence from bankruptcy.
The following table summarizes our option activity during 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
|
|
Weighted-Average Exercise Price
|
|
Weighted-Average Grant-Date Fair Value
|
|
Aggregate Intrinsic Value
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
Balance at December 31, 2019 (Predecessor)
|
1,427
|
|
|
$
|
59.00
|
|
|
$
|
16.81
|
|
|
$
|
—
|
|
|
Granted
|
593
|
|
|
$
|
6.82
|
|
|
$
|
3.31
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Cancelled or Forfeited
|
(2,020)
|
|
|
$
|
43.68
|
|
|
$
|
12.84
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at October 31, 2020 (Predecessor)
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 15 EQUITY
On the Effective Date, all our Predecessor common and preferred stock, including contracts on our equity were cancelled pursuant to the Plan and 83.3 million shares of new common stock were issued. See Note 2 Chapter 11 Proceedings for further information.
The following is a summary of changes in our common stock outstanding:
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
(in thousands)
|
|
Balance, December 31, 2018 (Predecessor)
|
48,650
|
|
|
Issued
|
694
|
|
|
Cancelled
|
(168)
|
|
|
Balance, December 31, 2019 (Predecessor)
|
49,176
|
|
|
Issued
|
451
|
|
|
Predecessor shares cancelled
|
(49,627)
|
|
|
Balance, October 31, 2020 (Predecessor)
|
—
|
|
|
Share Issuance
|
83,321
|
|
|
|
|
|
Balance, October 31, 2020 (Successor)
|
83,321
|
|
|
Share Issuance
|
—
|
|
|
Balance, December 31, 2020 (Successor)
|
83,321
|
|
Predecessor Employee Stock Purchase Plan
On May 26, 2020, our California Resources Corporation 2014 Employee Stock Purchase Plan was terminated by our then Board of Directors. No additional shares were issued under the plan after March 31, 2020.
Warrants
On the Effective Date, we issued Warrants for an aggregate 4.4 million shares of Successor common stock. The Warrants are exercisable for 5% of the outstanding shares of new common stock (on a fully diluted basis calculated immediately after the Effective Date) at an initial exercise price of $36 per share. The Warrants are exercisable from the Effective Date for a period of four years. The Warrant Agreement contains customary anti-dilution adjustments in the event of any stock split, reverse stock split, stock dividend, equity awards under the 2021 Incentive Plan or other distributions. The warrant holder may elect, in its sole discretion, to pay cash or to exercise on a cashless basis, pursuant to which the holder will not be required to pay cash for shares of common stock upon exercise of the warrant but will instead receive fewer shares.
Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss) consisted of unrealized losses associated with our pension and postretirement benefit plans for all periods presented. The elimination of Predecessor equity balances as part of fresh start accounting resulted in a reclassification of $23 million of accumulated other comprehensive loss to additional paid-in capital upon emergence. See Note 3 Fresh Start Accounting for additional information.
Unregistered Issuance of Equity Securities
Other than the shares issued in reliance of Section 4(a)(2) of the Securities Act as described below, we relied on Section 1145(a)(1) of the Bankruptcy Code as an exemption from the registration requirements of the Securities Act for the issuance of our new common stock and warrants. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under a plan of reorganization from registration under Section 5 of the Securities Act and state laws if three principal requirements are satisfied:
•The securities must be issued under a plan of reorganization by the debtor, its successor under a plan, or an affiliate participating in a joint plan of reorganization with the debtor;
•The recipients of the securities must hold a claim against, an interest in, or a claim for administrative expense in the case concerning the debtor or such affiliate; and
•The securities must be issued either (a) in exchange for the recipient’s claim against, interest in or claim for administrative expense in the case concerning the debtor or such affiliate or (b) principally in such exchange and partly for cash or property.
The (a) shares of new common stock issued pursuant to the Backstop Commitment Agreement, (b) shares of new common stock issued in connection with the payment of the backstop commitment premium and the exit fee for the Junior DIP Facility, and (c) Ares Settlement Stock issued to Ares pursuant to the Settlement Agreement were issued in each case without registration in reliance upon the exemption set forth in Section 4(a)(2) of the Securities Act and are therefore “restricted securities.”
On the Effective Date, we entered into a registration rights agreement with the backstop parties under the Backstop Commitment Agreement and each holder of at least 1% of the new common stock outstanding on the Effective Date, granting such parties customary registration rights with respect to their new common stock.
NOTE 16 EARNINGS PER SHARE
We compute basic and diluted earnings per share (EPS) using the two-class method required for participating
securities. Certain of our restricted and performance stock awards were considered participating securities because they had non-forfeitable dividend rights at the same rate as our Predecessor common stock.
Under the two-class method, undistributed earnings allocated to participating securities are 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 participating securities do not share in losses. For basic EPS, the weighted-average number of common shares outstanding excludes outstanding shares related to unvested restricted stock awards. Weighted-average shares were calculated based on the number of days in the Predecessor and Successor periods. For diluted EPS, the basic shares outstanding are adjusted by adding all potentially dilutive securities.
The following table presents the calculation of basic and diluted EPS.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
Years ended December 31,
|
|
|
|
|
|
2019
|
|
2018
|
|
(in millions, except per share amounts)
|
|
|
|
|
|
|
|
|
|
Basic EPS calculation
|
|
|
|
|
|
Net income (loss)
|
$
|
(125)
|
|
|
|
$
|
1,996
|
|
|
$
|
99
|
|
|
$
|
429
|
|
|
Less: Net income attributable to noncontrolling interests
|
2
|
|
|
|
(107)
|
|
|
(127)
|
|
|
(101)
|
|
|
Net (loss) income attributable to common stock
|
(123)
|
|
|
|
1,889
|
|
|
(28)
|
|
|
328
|
|
|
Less: Net income allocated to participating securities
|
—
|
|
|
|
(22)
|
|
|
—
|
|
|
(7)
|
|
|
Modification of noncontrolling interest(a)
|
—
|
|
|
|
138
|
|
|
—
|
|
|
—
|
|
|
Net (loss) income available to common stockholders
|
$
|
(123)
|
|
|
|
$
|
2,005
|
|
|
$
|
(28)
|
|
|
$
|
321
|
|
|
Weighted-average common shares outstanding
|
83.3
|
|
|
|
49.4
|
|
|
49.0
|
|
|
47.4
|
|
|
Basic EPS
|
$
|
(1.48)
|
|
|
|
$
|
40.59
|
|
|
$
|
(0.57)
|
|
|
$
|
6.77
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS calculation
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
(125)
|
|
|
|
$
|
1,996
|
|
|
$
|
99
|
|
|
$
|
429
|
|
|
Less: Net income attributable to noncontrolling interests
|
2
|
|
|
|
(107)
|
|
|
(127)
|
|
|
(101)
|
|
|
Net (loss) income attributable to common stock
|
(123)
|
|
|
|
1,889
|
|
|
(28)
|
|
|
328
|
|
|
Less: Net income allocated to participating securities
|
—
|
|
|
|
(22)
|
|
|
—
|
|
|
(7)
|
|
|
Modification of noncontrolling interest(a)
|
—
|
|
|
|
138
|
|
|
—
|
|
|
—
|
|
|
Net (loss) income available to common stockholders
|
$
|
(123)
|
|
|
|
$
|
2,005
|
|
|
$
|
(28)
|
|
|
$
|
321
|
|
|
Weighted-average common shares outstanding - Basic
|
83.3
|
|
|
|
49.4
|
|
|
49.0
|
|
|
47.4
|
|
|
Dilutive effect of potentially dilutive securities
|
—
|
|
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
Weighted-average common shares outstanding - Diluted
|
83.3
|
|
|
|
49.6
|
|
|
49.0
|
|
|
47.4
|
|
|
Diluted EPS
|
$
|
(1.48)
|
|
|
|
$
|
40.42
|
|
|
$
|
(0.57)
|
|
|
$
|
6.77
|
|
|
Weighted-average antidilutive shares
|
4.4
|
|
|
|
4.0
|
|
|
3.1
|
|
|
1.6
|
|
(a) Modification of noncontrolling interest relates to the deemed redemption of ECR's noncontrolling interest in the Ares JV in the third quarter of 2020. For more information on the Ares JV and the Settlement Agreement, see Note 7 Joint Ventures.
NOTE 17 PENSION AND POSTRETIREMENT BENEFIT PLANS
We have various qualified and non-qualified benefit plans for our salaried and union and nonunion hourly employees.
Defined Contribution Plans
All of our employees are eligible to participate in our tax-qualified, defined contribution retirement plan that provides for periodic cash contributions by us based on annual cash compensation and employee deferrals.
Certain salaried employees participate in supplemental plans that restore benefits lost due to government limitations on qualified plans. As of December 31, 2020 and 2019, we recognized $35 million and $37 million in other long-term liabilities for these supplemental plans, respectively.
We expensed $4 million in the Successor period and $28 million in the Predecessor period during 2020, $36 million in 2019 and $35 million in 2018 under the provisions of these defined contribution and supplemental plans.
Defined Benefit Plans
Participation in defined benefit pension plans sponsored by us is limited. During 2020, approximately 70 employees accrued benefits under these plans, all of whom were union employees. Effective December 31, 2015, the plans were amended such that participants other than union employees no longer earn benefits for service after December 31, 2015.
Pension costs for the defined benefit pension plans, determined by independent actuarial valuations, are funded by us through payments to trust funds, which are administered by independent trustees.
Postretirement Benefit Plans
We provide postretirement medical and dental benefits for our eligible former employees and their dependents. Our former employees are required to make monthly contributions to the plan, but the benefits are primarily funded by us as claims are paid during the year.
Obligations and Funded Status of our Defined Benefit Plans
The following table shows the amounts recognized on our balance sheets related to pension and postretirement benefit plans, as well as plans that we or our subsidiaries sponsor, as of December 31, 2020 and 2019 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
2020
|
|
|
2019
|
|
|
Pension
|
|
Postretirement
|
|
|
Pension
|
|
Postretirement
|
|
Amounts recognized on the balance sheet
|
|
|
|
|
|
|
|
|
|
Accrued liabilities
|
$
|
—
|
|
|
$
|
(4)
|
|
|
|
$
|
—
|
|
|
$
|
(3)
|
|
|
Other long-term liabilities
|
(15)
|
|
|
(125)
|
|
|
|
(18)
|
|
|
(113)
|
|
|
|
$
|
(15)
|
|
|
$
|
(129)
|
|
|
|
$
|
(18)
|
|
|
$
|
(116)
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts recognized in accumulated other comprehensive loss
|
$
|
(1)
|
|
|
$
|
(7)
|
|
|
|
$
|
(6)
|
|
|
$
|
(17)
|
|
The following table shows the funding status of our pension and post-retirement benefit plans along with a reconciliation of our benefit obligations and fair value of plan asset as of December 31, 2020 and 2019 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
January 1, 2019 - December 31, 2019
|
|
Pension
|
|
|
|
|
|
|
|
Changes in the benefit obligation
|
|
|
|
|
|
|
|
Benefit obligation—beginning balance
|
$
|
46
|
|
|
|
$
|
45
|
|
|
$
|
56
|
|
|
Service cost—benefits earned during the period
|
—
|
|
|
|
1
|
|
|
1
|
|
|
Interest cost on projected benefit obligation
|
—
|
|
|
|
1
|
|
|
2
|
|
|
Actuarial loss (gain)
|
3
|
|
|
|
1
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
Benefits paid
|
(2)
|
|
|
|
(2)
|
|
|
(25)
|
|
|
Benefit obligation—ending balance
|
$
|
47
|
|
|
|
$
|
46
|
|
|
$
|
45
|
|
|
|
|
|
|
|
|
|
|
Changes in plan assets
|
|
|
|
|
|
|
|
Fair value of plan assets—beginning balance
|
$
|
26
|
|
|
|
$
|
27
|
|
|
$
|
42
|
|
|
Actual gain (loss) return on plan assets
|
2
|
|
|
|
1
|
|
|
7
|
|
|
Employer contributions
|
6
|
|
|
|
—
|
|
|
3
|
|
|
Benefits paid
|
(2)
|
|
|
|
(2)
|
|
|
(25)
|
|
|
Fair value of plan assets—ending balance
|
$
|
32
|
|
|
|
$
|
26
|
|
|
$
|
27
|
|
|
|
|
|
|
|
|
|
|
Net benefit liability (unfunded status)
|
$
|
(15)
|
|
|
|
$
|
(20)
|
|
|
$
|
(18)
|
|
|
|
|
|
|
|
|
|
|
Postretirement
|
|
|
|
|
|
|
|
Changes in the benefit obligation (in millions)
|
|
|
|
|
|
|
|
Benefit obligation—beginning balance
|
$
|
122
|
|
|
|
$
|
116
|
|
|
$
|
84
|
|
|
Service cost—benefits earned during the period
|
1
|
|
|
|
4
|
|
|
4
|
|
|
Interest cost on projected benefit obligation
|
—
|
|
|
|
3
|
|
|
4
|
|
|
Actuarial loss (gain)
|
7
|
|
|
|
2
|
|
|
19
|
|
|
Cost of special termination benefits
|
—
|
|
|
|
—
|
|
|
6
|
|
|
Curtailment
|
—
|
|
|
|
—
|
|
|
2
|
|
|
Benefits paid
|
(1)
|
|
|
|
(3)
|
|
|
(3)
|
|
|
Benefit obligation—ending balance
|
$
|
129
|
|
|
|
$
|
122
|
|
|
$
|
116
|
|
|
|
|
|
|
|
|
|
|
Changes in plan assets
|
|
|
|
|
|
|
|
Fair value of plan assets—beginning balance
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
Employer contributions
|
1
|
|
|
|
3
|
|
|
3
|
|
|
Benefits paid
|
(1)
|
|
|
|
(3)
|
|
|
(3)
|
|
|
Fair value of plan assets—ending balance
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
Net benefit liability (unfunded status)
|
$
|
(129)
|
|
|
|
$
|
(122)
|
|
|
$
|
(116)
|
|
Our accumulated benefit obligation for our defined benefit pension plans exceeded the fair value of our plan assets as shown in the table below for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
2020
|
|
|
2019
|
|
(in millions)
|
|
|
|
|
|
Projected benefit obligation
|
$
|
47
|
|
|
|
$
|
45
|
|
|
Accumulated benefit obligation
|
$
|
43
|
|
|
|
$
|
41
|
|
|
Fair value of plan assets
|
$
|
32
|
|
|
|
$
|
27
|
|
Components of Net Periodic Benefit Cost
We record the service cost component of net periodic pension cost with other employee compensation and all other components, including settlement costs, are reported as other non-operating expenses on our consolidated statements of operations. The following table set forth the components of our net periodic pension and postretirement benefit costs (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
Years ended
December 31,
|
|
|
|
|
|
2019
|
|
2018
|
|
Pension
|
|
|
|
|
|
|
|
|
|
Net periodic benefit costs
|
|
|
|
|
|
|
|
|
|
Service cost—benefits earned during the period
|
$
|
—
|
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
Interest cost on projected benefit obligation
|
—
|
|
|
|
1
|
|
|
2
|
|
|
2
|
|
|
Expected return on plan assets
|
—
|
|
|
|
(1)
|
|
|
(2)
|
|
|
(3)
|
|
|
Amortization of net actuarial loss
|
—
|
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
Settlement costs
|
—
|
|
|
|
1
|
|
|
9
|
|
|
4
|
|
|
Net periodic benefit costs
|
$
|
—
|
|
|
|
$
|
3
|
|
|
$
|
11
|
|
|
$
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement
|
|
|
|
|
|
|
|
|
|
Net periodic benefit costs
|
|
|
|
|
|
|
|
|
|
Service cost—benefits earned during the period
|
$
|
1
|
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
Interest cost on projected benefit obligation
|
—
|
|
|
|
3
|
|
|
4
|
|
|
4
|
|
|
Expected return on plan assets
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Cost of special termination benefits
|
—
|
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
Amortization of net actuarial loss
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Settlement costs
|
—
|
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
Net periodic benefit costs
|
$
|
1
|
|
|
|
$
|
8
|
|
|
$
|
14
|
|
|
$
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of accumulated other comprehensive income (loss) (AOCI) are presented net of tax. The following table presents the changes in plan assets and benefit obligations recognized in other comprehensive (loss) income before tax (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
Years ended
December 31,
|
|
|
|
|
|
2019
|
|
2018
|
|
Pension
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial (loss) gain
|
$
|
(1)
|
|
|
|
$
|
(1)
|
|
|
$
|
(6)
|
|
|
$
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement costs
|
—
|
|
|
|
1
|
|
|
9
|
|
|
4
|
|
|
Amortization of net actuarial gain/loss
|
—
|
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
Total recognized in other comprehensive (loss) income
|
$
|
(1)
|
|
|
|
$
|
1
|
|
|
$
|
4
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial (loss) gain
|
$
|
(7)
|
|
|
|
$
|
(2)
|
|
|
$
|
(19)
|
|
|
$
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement costs
|
—
|
|
|
|
1
|
|
|
(2)
|
|
|
—
|
|
|
Amortization of net actuarial gain/loss
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total recognized in other comprehensive (loss) income
|
$
|
(7)
|
|
|
|
$
|
(1)
|
|
|
$
|
(21)
|
|
|
$
|
14
|
|
Settlement costs related to our pension and postretirement plans were associated with early retirements.
The following table sets forth the valuation assumptions, on a weighted-average basis, used to determine our benefit obligations and net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
January 1, 2019 - December 31, 2019
|
|
Pension
|
|
|
|
|
|
|
|
Benefit Obligation Assumptions
|
|
|
|
|
|
|
|
Discount rate
|
2.42
|
%
|
|
|
2.70
|
%
|
|
3.16
|
%
|
|
Rate of compensation increase
|
4.00
|
%
|
|
|
4.00
|
%
|
|
4.00
|
%
|
|
Net Periodic Benefit Cost Assumptions
|
|
|
|
|
|
|
|
Discount rate
|
2.70
|
%
|
|
|
3.16
|
%
|
|
4.22
|
%
|
|
Assumed long-term rate of return on assets
|
5.42
|
%
|
|
|
5.42
|
%
|
|
6.50
|
%
|
|
Rate of compensation increase
|
4.00
|
%
|
|
|
4.00
|
%
|
|
4.00
|
%
|
|
|
|
|
|
|
|
|
|
Postretirement
|
|
|
|
|
|
|
|
Benefit Obligation Assumptions
|
|
|
|
|
|
|
|
Discount rate
|
2.92
|
%
|
|
|
3.11
|
%
|
|
3.48
|
%
|
|
Net Periodic Benefit Cost Assumptions
|
|
|
|
|
|
|
|
Discount rate
|
3.11
|
%
|
|
|
3.48
|
%
|
|
4.57
|
%
|
For pension plans and postretirement benefit plans that we or our subsidiaries sponsor, we based the discount rate on the Aon AA Above Median yield curve in both 2020 and 2019. The weighted-average rate of increase in future compensation levels is consistent with our past and anticipated future compensation increases for employees participating in retirement plans that determine benefits using compensation. The assumed long-term rate of return on assets is estimated with regard to current market factors but within the context of historical returns for the asset mix that exists at year end.
In 2020, we used the Society of Actuaries Pri-20212 mortality assumptions reflecting the MP-2020 scale which plan sponsors in the U.S. use in the actuarial valuations that determine a plan sponsor’s pension and postretirement obligations. Changes in mortality assumptions were reflected in the valuations of our pension and postretirement benefit obligations as part of fresh start accounting upon emergence from bankruptcy. These assumptions did not significantly change our pension benefit obligations or postretirement benefit obligations in 2020 as compared to the prior year.
The postretirement benefit obligation was determined by application of the terms of medical and dental benefits, including the effect of established maximums on covered costs, together with relevant actuarial assumptions and healthcare cost trend rates projected at an assumed U.S. Consumer Price Index (CPI) increase of 2.06% and 1.86% as of December 31, 2020 and 2019, respectively. Under the terms of our postretirement plans, participants other than certain union employees pay for all medical cost increases in excess of increases in the CPI. For those union employees, we projected that, as of December 31, 2020, health care cost trend rates would decrease from 6.50%-7.00% in 2020 until they reach 4.50% in 2028 and remain at 4.50% thereafter.
The actuarial assumptions used could change in the near term as a result of changes in expected future trends and other factors that, depending on the nature of the changes, could cause increases or decreases in the plan assets and liabilities.
Fair Value of Plan Assets
We employ a total return investment approach that uses a diversified blend of equity and fixed-income investments to optimize the long-term return of plan assets at a prudent level of risk. Equity investments were diversified across U.S. and non-U.S. stocks, as well as differing styles and market capitalizations. Other asset classes, such as private equity and real estate, may have been used with the goals of enhancing long-term returns and improving portfolio diversification. In 2020 and 2019, the target allocation of plan assets was 65% equity securities and 35% debt securities. Investment performance was measured and monitored on an ongoing basis through quarterly investment portfolio and manager guideline compliance reviews, annual liability measurements and periodic studies.
The fair values of our pension plan assets by asset category are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
December 31, 2020 (Successor)
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Asset Class
|
(in millions)
|
|
Cash equivalents
|
$
|
6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6
|
|
|
Commingled funds
|
|
|
|
|
|
|
|
|
Fixed income
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
U.S. equity
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
|
International equity
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
Mutual funds
|
|
|
|
|
|
|
|
|
Bond funds
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
Blend funds
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Value funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
Growth funds
|
6
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
Guaranteed deposit account
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
|
Total pension plan assets
|
$
|
19
|
|
|
$
|
7
|
|
|
$
|
6
|
|
|
$
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
December 31, 2019 (Predecessor)
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Asset Class
|
(in millions)
|
|
Cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Commingled funds
|
|
|
|
|
|
|
|
|
Fixed income
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
|
U.S. equity
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
|
International equity
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
Mutual funds
|
|
|
|
|
|
|
|
|
Bond funds
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
Blend funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
Value funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
Growth funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
Guaranteed deposit account
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|
Total pension plan assets
|
$
|
11
|
|
|
$
|
9
|
|
|
$
|
7
|
|
|
$
|
27
|
|
Expected Contributions and Benefit Payments
In 2021, we expect to contribute $5 million to our pension and $5 million to our postretirement benefit plans. Estimated future undiscounted benefit payments by the plans, which reflect expected future service, as appropriate, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
|
For the years ended December 31,
|
(in millions)
|
|
2021
|
$
|
13
|
|
|
$
|
5
|
|
|
2022
|
$
|
2
|
|
|
$
|
5
|
|
|
2023
|
$
|
3
|
|
|
$
|
5
|
|
|
2024
|
$
|
2
|
|
|
$
|
5
|
|
|
2025
|
$
|
3
|
|
|
$
|
5
|
|
|
2026 to 2030 Payouts
|
$
|
11
|
|
|
$
|
27
|
|
NOTE 18 REVENUE RECOGNITION
The following table provides disaggregated revenue from contracts with customers:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
Years ended December 31,
|
|
(in millions)
|
|
|
|
2019
|
|
2018
|
|
Oil and natural gas sales
|
|
|
|
|
|
|
|
|
|
Oil
|
$
|
176
|
|
|
|
$
|
874
|
|
|
$
|
1,884
|
|
|
$
|
2,110
|
|
|
NGLs
|
29
|
|
|
|
106
|
|
|
179
|
|
|
260
|
|
|
Natural gas
|
32
|
|
|
|
112
|
|
|
207
|
|
|
220
|
|
|
|
237
|
|
|
|
1,092
|
|
|
2,270
|
|
|
2,590
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity sales
|
15
|
|
|
|
86
|
|
|
112
|
|
|
111
|
|
|
Trading revenue
|
38
|
|
|
|
124
|
|
|
286
|
|
|
330
|
|
|
Other revenue
|
3
|
|
|
|
14
|
|
|
25
|
|
|
32
|
|
|
|
56
|
|
|
|
224
|
|
|
423
|
|
|
473
|
|
|
Net derivative (loss) gain from commodity contracts
|
(141)
|
|
|
|
91
|
|
|
(59)
|
|
|
1
|
|
|
Total revenues
|
$
|
152
|
|
|
|
$
|
1,407
|
|
|
$
|
2,634
|
|
|
$
|
3,064
|
|
Commodity Sales Contracts
We recognize revenue from the sale of our production when delivery has occurred and control passes to the customer. Our contracts with customers are short term, typically less than a year. We consider our performance obligations to be satisfied upon transfer of control of the commodity. In certain instances, transportation and processing fees are incurred by us prior to control being transferred to customers. We record these costs as a component of other expenses, net on our consolidated statements of operations.
Our commodity sales contracts are based on index prices. We recognize revenue in the amount that we expect to receive once we are able to adequately estimate the consideration (i.e., when market prices are known). Our contracts with customers typically require payment within 30 days following invoicing.
Electricity
The electrical output of our Elk Hills power plant that is not used in our operations is sold to the wholesale power market and to a utility under a power purchase and sales agreement (PPA) through December 2023, which includes a monthly capacity payment plus a variable payment based on the quantity of power purchased each month. Revenue is recognized when obligations under the terms of a contract are satisfied; generally, this occurs upon delivery of the electricity. Revenue is measured as the amount of consideration we expect to receive based on average index or California Independent System Operator (CAISO) market pricing with payment due the month following delivery. Payments under our PPA are settled monthly. We consider our performance obligations to be satisfied upon delivery of electricity or as the contracted amount of energy is made available to the customer in the case of capacity payments.
Trading Revenue and Other
To transport our natural gas as well as third-party volumes, we have entered into firm pipeline commitments. In addition, we may from time-to-time enter into natural gas purchase and sale agreements with third parties to take advantage of market dislocations. We consider our performance obligations to be satisfied upon transfer of control of the commodity.
We report our trading revenue in total revenues and associated purchases of commodities related to our trading activities are reported in other expenses, net on our consolidated statements of operations.
NOTE 19 SUBSEQUENT EVENTS
In January 2021, we completed an offering of $600 million of Senior Notes. The net proceeds of $590 million were used to repay in full our Second Lien Term Loan and EHP Notes, with the remainder used to repay a portion of the outstanding borrowings under our Revolving Credit Facility. The Senior Notes are general unsecured obligations which are guaranteed on a senior unsecured basis by certain of our material subsidiaries. We may redeem some or all of the Senior Notes at any time on or after February 1, 2023 at specified redemption prices. Prior to such time, we may redeem up to 35% of the aggregate principal amount of the Senior Notes using cash from certain equity offerings at specified redemption prices. If we experience certain change of control events, we will be required to offer to repurchase the Senior Notes at a premium. The indenture contains other customary terms, events of default and covenants.
Refer to Note 14 Stock-Based Compensation for the approval of our 2021 Incentive Plan and related issuances of awards.
Quarterly Financial Data (Unaudited)
Not applicable.
Supplemental Oil and Gas Information (Unaudited)
The following table sets forth our net operating and non-operating interests in quantities of proved developed and undeveloped reserves of oil (including condensate), NGLs and natural gas and changes in such quantities. Estimated reserves include our economic interests under PSC-type contracts relating to our Wilmington field in Long Beach. All of our proved reserves are located within the state of California.
PROVED DEVELOPED AND UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil(a)
|
|
NGLs
|
|
Natural Gas
|
|
Total(b)
|
|
|
(MMBbl)
|
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBoe)
|
|
Balance at December 31, 2017
|
442
|
|
|
58
|
|
|
706
|
|
|
618
|
|
|
Revisions of previous estimates(c)
|
51
|
|
|
(4)
|
|
|
(15)
|
|
|
44
|
|
|
Improved recovery
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
Extensions and discoveries
|
25
|
|
|
1
|
|
|
27
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
38
|
|
|
11
|
|
|
89
|
|
|
64
|
|
|
Production
|
(30)
|
|
|
(6)
|
|
|
(73)
|
|
|
(48)
|
|
|
Balance at December 31, 2018
|
530
|
|
|
60
|
|
|
734
|
|
|
712
|
|
|
Revisions of previous estimates(c)
|
(34)
|
|
|
(4)
|
|
|
(52)
|
|
|
(47)
|
|
|
Improved recovery
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
Extensions and discoveries
|
24
|
|
|
2
|
|
|
41
|
|
|
33
|
|
|
Divestitures
|
(11)
|
|
|
—
|
|
|
6
|
|
|
(10)
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
(29)
|
|
|
(6)
|
|
|
(75)
|
|
|
(47)
|
|
|
Balance at December 31, 2019
|
483
|
|
|
52
|
|
|
654
|
|
|
644
|
|
|
Revisions of previous estimates(c)
|
(164)
|
|
|
(7)
|
|
|
(86)
|
|
|
(185)
|
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Extensions and discoveries
|
20
|
|
|
1
|
|
|
24
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
Divestitures
|
(1)
|
|
|
—
|
|
|
(3)
|
|
|
(2)
|
|
|
Production
|
(25)
|
|
|
(5)
|
|
|
(62)
|
|
|
(40)
|
|
|
Balance at December 31, 2020
|
313
|
|
|
41
|
|
|
527
|
|
|
442
|
|
|
|
|
|
|
|
|
|
|
|
PROVED DEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
December 31, 2017
|
304
|
|
|
45
|
|
|
543
|
|
|
440
|
|
|
December 31, 2018
|
389
|
|
|
47
|
|
|
565
|
|
|
530
|
|
|
December 31, 2019
|
357
|
|
|
45
|
|
|
543
|
|
|
493
|
|
|
December 31, 2020(d)
|
266
|
|
|
39
|
|
|
460
|
|
|
382
|
|
|
|
|
|
|
|
|
|
|
|
PROVED UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
December 31, 2017
|
138
|
|
|
13
|
|
|
163
|
|
|
178
|
|
|
December 31, 2018
|
141
|
|
|
13
|
|
|
169
|
|
|
182
|
|
|
December 31, 2019
|
126
|
|
|
7
|
|
|
111
|
|
|
151
|
|
|
December 31, 2020
|
47
|
|
|
2
|
|
|
67
|
|
|
60
|
|
(a)Includes proved reserves related to economic arrangements similar to PSCs of 85 MMBbl, 125 MMBbl, 131 MMBbl and 108 MMBbl at December 31, 2020, 2019, 2018 and 2017, respectively.
(b)Natural gas volumes have been converted to Boe based on the equivalence of energy content of six Mcf of natural gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
(c)Commodity price changes affect the proved reserves we record. For example, higher prices generally increase the economically recoverable reserves in all of our operations, because the extra margin extends their expected lives and renders more projects economic. Partially offsetting this effect, higher prices decrease our share of proved cost recovery reserves under arrangements similar to production-sharing contracts at our Wilmington field in Long Beach because fewer reserves are required to recover costs. Conversely, when prices drop, we experience the opposite effects. Performance-related revisions can include upward or downward changes to previous proved reserves estimates due to the evaluation or interpretation of recent geologic, production decline or operating performance data.
(d)Approximately 27% of proved developed oil reserves, 13% of proved developed NGLs reserves, 16% of proved developed natural gas reserves and, overall, 24% of total proved developed reserves at December 31, 2020 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.
2020
Revisions of previous estimates – We had negative price-related revisions of 72 MMBoe primarily resulting from a lower commodity price environment in 2020 compared to 2019. The net price revision reflects the shortened economic lives of our fields, as estimated using 2020 SEC pricing, which for oil was significantly lower than current prices, partially offset by our lower operating costs.
We had 61 MMBoe of net negative performance-related revisions which included negative performance-related revisions of 73 MMBoe and positive performance-related revisions of 12 MMBoe. Our negative performance-related revisions are primarily related to wells that underperformed their forecasts. A significant factor for this underperformance was a reduction in our capital program in 2020 due to the extremely low commodity price environment and constraints during our bankruptcy process. This led to higher overall decline rates due to injection curtailments, capacity limitations and reduced well maintenance. Our positive performance-related revisions of 12 MMBoe primarily related to better-than-expected well performance.
We removed 52 MMBoe of proved undeveloped reserves, all of which were no longer included in our development plans because they did not meet internal investment thresholds at lower SEC prices. The majority of these revisions were located in the San Joaquin and Los Angeles basins.
Extensions and discoveries – We added 25 MMBoe from extensions and discoveries, approximately half of which resulted from the booking of proved undeveloped reserves in connection with fresh start accounting. Successful drilling and workovers in the San Joaquin and Los Angeles basins also contributed to the increase.
2019
Revisions of previous estimates – We had negative price-related revisions of 20 MMBoe primarily resulting from a lower commodity-price environment in 2019 compared to 2018.
We had 16 MMBoe of net positive performance-related revisions. We added 23 MMBoe primarily related to better-than-expected performance in the San Joaquin and Los Angeles basins and 18 MMBoe that had been previously removed due to budgeting and development timing. These volumes were brought back into our reserves based on re-evaluation of the applicable areas and management's plans. These positive revisions were partially offset by 25 MMBoe in negative performance-related revisions primarily related to delayed responses in certain waterflood and steamflood projects.
We removed 43 MMBoe of proved undeveloped reserves, of which 19 MMBoe related to expired projects not developed within the five-year window as the result of lower-than-anticipated product prices. The remaining 24 MMBoe had not yet expired but were no longer prioritized in our development plans in the current commodity price environment. The majority of these proved undeveloped reserves that were downgraded at management's discretion are located in the San Joaquin basin, meet economic investment criteria at current prices and are anticipated to be developed in the future.
Extensions and discoveries – We added 33 MMBoe from extensions and discoveries, primarily resulting from successful drilling in the San Joaquin and Los Angeles basins.
Improved recovery – We also added 3 MMBoe from improved recovery through IOR and EOR methods, which were associated with the continued development of steamflood and waterflood properties in the San Joaquin basin.
Divestitures – We had a reduction of 10 MMBoe in connection with the Lost Hills divestiture and the Alpine JV entered into during the year. See Part II, Item 7 Management's Discussion and Analysis, Acquisitions and Divestitures for more on the Lost Hills divestiture and Part II, Item 7 Management's Discussion and Analysis, Joint Ventures for more on the Alpine JV.
2018
Revisions of previous estimates – Our 2018 realized prices for oil and natural gas increased over the prior year by 39% and 14%, respectively, which resulted in positive price-related revisions of 38 MMBoe. We also added 6 MMBoe from net positive performance-related revisions of which 27 MMBoe were from positive technical revisions primarily due to better-than-expected performance and successful drilling efforts in the San Joaquin and Los Angeles basins.
Additionally, at management's discretion, we removed a total of 21 MMBoe of proved undeveloped reserves that were not yet expired but that were not anticipated to be developed within their five-year window of initial booking. Approximately 11 MMBoe of these downgraded proved undeveloped reserves expired in 2019 and were not anticipated to be developed before then at current oil prices. The remaining 10 MMBoe of downgraded proved undeveloped reserves were projects that are no longer prioritized in our development plan based on current project economics.
Improved recovery – We also added 4 MMBoe from improved recovery through proven IOR and EOR methods. The improved recovery additions were associated with the continued development of steamflood and waterflood properties in the San Joaquin basin.
Extensions and discoveries – We added 30 MMBoe from extensions and discoveries, primarily resulting from new geologic interpretations and pressure data in the Ventura basin along with successful drilling in San Joaquin and Los Angeles basins.
Acquisitions – We also added 64 MMBoe in connection with the acquisitions during the year, the majority of which resulted from the Elk Hills transaction.
CAPITALIZED COSTS
Capitalized costs relating to oil and natural gas producing activities and related accumulated depreciation, depletion and amortization (DD&A) were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
December 31, 2020
|
|
|
December 31, 2019
|
|
|
(in millions)
|
|
|
(in millions)
|
|
Proved properties
|
$
|
2,416
|
|
|
|
$
|
21,285
|
|
|
Unproved properties
|
1
|
|
|
|
1,055
|
|
|
Total capitalized costs(a)
|
2,417
|
|
|
|
22,340
|
|
|
Accumulated depreciation, depletion and amortization(b)
|
(31)
|
|
|
|
(16,300)
|
|
|
Net capitalized costs
|
$
|
2,386
|
|
|
|
$
|
6,040
|
|
(a)Includes acquisition and development costs.
(b)No valuation allowance was recorded for unproved properties at December 31, 2020. Balance at December 31, 2019 includes an accumulated valuation allowance for total unproved properties of $823 million.
COSTS INCURRED
Costs incurred relating to oil and natural gas activities include capital investments, exploration (whether expensed or capitalized), acquisitions and asset retirement obligations but exclude corporate items. The following table summarizes our costs incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
For the years ended
|
|
|
|
|
|
2019
|
|
2018
|
|
Property acquisition costs
|
(in millions)
|
|
|
(in millions)
|
|
Proved properties
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
553
|
|
|
Unproved properties
|
—
|
|
|
|
—
|
|
|
4
|
|
|
1
|
|
|
Exploration costs
|
1
|
|
|
|
10
|
|
|
30
|
|
|
38
|
|
|
Development costs(a)
|
7
|
|
|
|
35
|
|
|
505
|
|
|
652
|
|
|
Costs incurred
|
$
|
8
|
|
|
|
$
|
45
|
|
|
$
|
540
|
|
|
$
|
1,244
|
|
(a)There were no costs incurred for development costs related to ARO in 2020. Development costs include a $80 million increase and $7 million decrease in ARO in 2019 and 2018, respectively. Development costs in 2019 reflect an allocation related to a warrant issued in connection with the Alpine JV of $3 million.
RESULTS OF OPERATIONS
Our oil and natural gas producing activities, which exclude items such as asset dispositions, corporate overhead and interest, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
November 1, 2020 - December 31, 2020
|
|
|
January 1, 2020 - October 31, 2020
|
|
|
(millions)
|
|
($/Boe)(a)
|
|
|
(millions)
|
|
($/Boe)(a)
|
|
Revenues(b)
|
$
|
235
|
|
|
$
|
37.49
|
|
|
|
$
|
1,196
|
|
|
$
|
34.98
|
|
|
Operating costs(c)
|
114
|
|
|
18.19
|
|
|
|
511
|
|
|
14.95
|
|
|
General and administrative expenses
|
7
|
|
|
1.12
|
|
|
|
38
|
|
|
1.11
|
|
|
Other operating expenses(d)
|
14
|
|
|
2.22
|
|
|
|
53
|
|
|
1.55
|
|
|
Depreciation, depletion and amortization
|
31
|
|
|
4.95
|
|
|
|
299
|
|
|
8.75
|
|
|
Taxes other than on income
|
4
|
|
|
0.64
|
|
|
|
106
|
|
|
3.10
|
|
|
Asset impairment
|
—
|
|
|
—
|
|
|
|
1,733
|
|
|
50.69
|
|
|
Exploration expenses
|
1
|
|
|
0.16
|
|
|
|
10
|
|
|
0.29
|
|
|
Pretax income
|
64
|
|
|
10.21
|
|
|
|
(1,554)
|
|
|
(45.46)
|
|
|
Income tax expense(e)
|
(18)
|
|
|
(2.87)
|
|
|
|
435
|
|
|
12.72
|
|
|
Results of operations
|
$
|
46
|
|
|
$
|
7.34
|
|
|
|
$
|
(1,119)
|
|
|
$
|
(32.74)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
2019
|
|
2018
|
|
|
|
|
|
|
(millions)
|
|
($/Boe)(a)
|
|
(millions)
|
|
($/Boe)(a)
|
|
Revenues(b)
|
|
|
|
|
$
|
2,377
|
|
|
$
|
50.88
|
|
|
$
|
2,359
|
|
|
$
|
48.84
|
|
|
Operating costs(c)
|
|
|
|
|
895
|
|
|
19.16
|
|
|
912
|
|
|
18.88
|
|
|
General and administrative expenses
|
|
|
|
|
56
|
|
|
1.20
|
|
|
49
|
|
|
1.01
|
|
|
Other operating expenses(d)
|
|
|
|
|
71
|
|
|
1.52
|
|
|
51
|
|
|
1.07
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
439
|
|
|
9.40
|
|
|
469
|
|
|
9.71
|
|
|
Taxes other than on income
|
|
|
|
|
121
|
|
|
2.59
|
|
|
117
|
|
|
2.42
|
|
|
Asset impairment
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Exploration expenses
|
|
|
|
|
29
|
|
|
0.62
|
|
|
34
|
|
|
0.70
|
|
|
Pretax income
|
|
|
|
|
766
|
|
|
16.39
|
|
|
727
|
|
|
15.05
|
|
|
Income tax expense(e)
|
|
|
|
|
(205)
|
|
|
(4.39)
|
|
|
(180)
|
|
|
(3.85)
|
|
|
Results of operations
|
|
|
|
|
$
|
561
|
|
|
$
|
12.00
|
|
|
$
|
547
|
|
|
$
|
11.20
|
|
(a)Natural gas volumes have been converted to Boe based on the equivalence of energy content of six Mcf of natural gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
(b)Revenues include cash settlements on our commodity derivatives which are reported in net derivative (gain) loss from commodity contracts on our consolidated statements of operations.
(c)Operating costs are the costs incurred in lifting the oil and natural gas to the surface and include gathering, processing, field storage and insurance on proved properties. Operating costs on a per Boe basis, excluding the effects of PSC-type contracts, were $14.14 and 16.86 for the Successor and Predecessor periods of 2020, respectively. Operating costs on a per Boe basis, excluding the effects of PSC-type contracts, were $17.70 and $17.47 for the years 2019 and 2018, respectively.
(d)Other operating expenses primarily include accretion on our asset retirement obligations and transportation costs.
(e)Income taxes are calculated on the basis of a stand-alone tax filing entity. The combined U.S. federal and California statutory tax rate was 28%. The effective tax rate for 2018 reflects the benefit of enhanced oil recovery tax credits.
STANDARDIZED MEASURE, INCLUDING YEAR-TO-YEAR CHANGES THEREIN, OF DISCOUNTED FUTURE NET CASH FLOWS
For purposes of the following disclosures, discounted future net cash flows were computed by applying to our proved oil and natural gas reserves the unweighted arithmetic average of the first-day-of-the-month price for each month within the years ended December 31, 2020, 2019 and 2018, respectively. The realized prices used to calculate future cash flows vary by producing area and market conditions. Future operating and capital costs were determined using the current cost environment applied to expectations of future operating and development activities. Future income tax expense was computed by applying, generally, year-end statutory tax rates (adjusted for permanent differences and tax credits) to the estimated net future pre-tax cash flows, after allowing for the deductions for intangible drilling costs and tax DD&A. The cash flows were discounted using a 10% discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions at December 31, 2020, 2019 and 2018. Such assumptions, which are prescribed by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to substantially different results.
Standardized Measure of Discounted Future Net Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
December 31, 2020
|
|
|
December 31, 2019
|
|
December 31, 2018
|
|
(in millions)
|
|
|
|
|
|
|
|
Future cash inflows
|
$
|
15,532
|
|
|
|
$
|
34,134
|
|
|
$
|
42,325
|
|
|
Future costs
|
|
|
|
|
|
|
|
Operating costs(a)
|
(9,389)
|
|
|
|
(16,724)
|
|
|
(19,452)
|
|
|
Development costs(b)
|
(2,392)
|
|
|
|
(3,938)
|
|
|
(4,432)
|
|
|
Future income tax expense
|
(701)
|
|
|
|
(3,180)
|
|
|
(4,231)
|
|
|
Future net cash flows
|
3,050
|
|
|
|
10,292
|
|
|
14,210
|
|
|
Ten percent discount factor
|
(1,118)
|
|
|
|
(5,061)
|
|
|
(6,935)
|
|
|
Standardized measure of discounted future net cash flows
|
$
|
1,932
|
|
|
|
$
|
5,231
|
|
|
$
|
7,275
|
|
(a)Includes general and administrative expenses and taxes other than on income.
(b)Includes asset retirement costs.
Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserve Quantities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
2020
|
|
|
2019
|
|
2018
|
|
(in millions)
|
|
|
|
|
|
|
|
Beginning of year
|
$
|
5,231
|
|
|
|
$
|
7,275
|
|
|
$
|
3,765
|
|
|
Sales of oil and natural gas, net of production and other operating costs
|
(1,257)
|
|
|
|
(1,198)
|
|
|
(1,511)
|
|
|
Changes in price, net of production and other operating costs
|
(3,940)
|
|
|
|
(1,998)
|
|
|
3,648
|
|
|
Previously estimated development costs incurred
|
519
|
|
|
|
556
|
|
|
351
|
|
|
Change in estimated future development costs
|
1,032
|
|
|
|
(283)
|
|
|
(38)
|
|
|
Extensions, discoveries and improved recovery, net of costs
|
122
|
|
|
|
433
|
|
|
443
|
|
|
Revisions of previous quantity estimates(a)
|
(1,407)
|
|
|
|
(638)
|
|
|
738
|
|
|
Accretion of discount
|
650
|
|
|
|
890
|
|
|
427
|
|
|
Net change in income taxes
|
1,124
|
|
|
|
518
|
|
|
(1,356)
|
|
|
Purchases and sales of reserves in place
|
(25)
|
|
|
|
(151)
|
|
|
766
|
|
|
Changes in production rates and other
|
(117)
|
|
|
|
(173)
|
|
|
42
|
|
|
Net change
|
(3,299)
|
|
|
|
(2,044)
|
|
|
3,510
|
|
|
End of year
|
$
|
1,932
|
|
|
|
$
|
5,231
|
|
|
$
|
7,275
|
|
(a)Includes revisions related to performance and price changes.
