|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. We were incorporated in Delaware as a wholly owned subsidiary of Occidental Petroleum Corporation (Occidental) on April 23, 2014, and we became an independent, publicly traded company on December 1, 2014.
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. The assets and liabilities in the consolidated financial statements are presented on a historical cost basis. We have eliminated significant intercompany transactions and accounts. We account for our share of oil and natural gas production 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 balance sheets, statements of operations and cash flows.
Risks and Uncertainties
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 and 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
For the year ended December 31, 2019, our principal customers, Phillips 66 Company and Valero Marketing & Supply Company, each accounted for at least 10%, and collectively accounted for 46%, of our oil and natural gas sales before the effects of hedging. For the year ended December 31, 2018, our principal customers, Phillips 66 Company and Valero Marketing & Supply Company, each accounted for at least 10%, and collectively accounted for 43%, of our oil and natural gas sales before the effects of hedging. For the year ended December 31, 2017, our principal customers, Phillips 66 Company, Andeavor Logistic LP, Valero Marketing & Supply Company and Shell Trading (US) Company, each accounted for at least 10%, and collectively accounted for 67%, of our revenue excluding the impact of derivative gains and losses.
Critical Accounting Policies
Property, Plant and Equipment
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 additional 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 – A portion of the carrying value of our oil and natural gas properties is attributable to unproved properties. At December 31, 2019, the net capitalized costs attributable to unproved properties were approximately $232 million. 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 based on the initially determined rate, not based on specific areas, leases or other units. 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 using a risk-adjusted discount rate.
Commodity and interest-rate derivatives are carried at fair value. For commodity derivatives, we utilize the mid-point between bid and ask prices for valuing these instruments. For interest-rate derivatives, we utilize the London Interbank Offered Rate (LIBOR) forward curve. In addition to using market data in determining these fair values, we make assumptions about the risks inherent in the inputs to the valuation technique. 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) is written down to fair value if we determine that there has been an impairment in its value. 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 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.
Other Accounting Policies
We recognize revenue in accordance with ASC 606, Revenue from Contracts with Customers, which is more fully described in Note 15 Revenue Recognition.
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 market. Inventories as of December 31, 2019 and 2018 consisted of the following:
Materials and supplies
Our derivative contracts are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. Since we did not apply hedge accounting for any of the periods presented, we recognize any fair value gains or losses on a net basis, over the remaining term of the instrument, in our consolidated statement 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
We have stockholder-approved stock-based incentive plans for certain executives, employees and non-employee directors that are more fully described in Note 11 Stock Compensation.
Earnings Per Share
We compute basic and diluted earnings per share (EPS) using the two-class method required for participating securities. 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. For basic EPS, the weighted-average number of common shares outstanding excludes outstanding shares related to unvested restricted stock awards. For diluted EPS, the basic shares outstanding are adjusted by adding potentially dilutive securities.
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 estimated 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 property, plant and equipment (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.
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 summarizes the activity of our ARO, of which $489 million and $402 million are included in other long-term liabilities, with the remaining portion in accrued liabilities at December 31, 2019 and 2018, respectively.
For the years ended
Liabilities incurred, capitalized to PP&E
Liabilities settled and paid
Acquisitions, capitalized to PP&E(a)
Dispositions, reduction to PP&E
For the year ended December 31, 2018, amount includes $7 million related to the Elk Hills transaction and $1 million related to other acquisitions.
The timing of our cash flows and additional testing costs associated with our future asset retirement activities were adjusted in 2019 due to new idle well regulations enacted in the first quarter. These new regulations 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 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 loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. We review our loss contingencies on an ongoing basis.
Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings, or other factors.
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases. Deferred tax assets are recognized when it is more likely than not that they will be realized. We periodically assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized.
We recognize the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a tax authority. We recognize interest and penalties, if any, related to uncertain tax positions as a component of the income tax provision. No interest or penalties related to uncertain tax positions were recognized in the financial statements for the periods presented.
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 production costs. We record a share of production and reserves to recover a portion of such capital and production costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and production 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 production costs. However, our net economic benefit is greater when product prices are higher. The contracts represented approximately 15% of our production for the year ended December 31, 2019.
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 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 using a December 31 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.
Actuarial gains and losses that have not yet been recognized through income are recorded in accumulated other comprehensive income within equity, net of taxes, until they are amortized as a component of net periodic benefit cost.
Cash at December 31, 2019 and 2018 included approximately $3 million and $2 million, respectively, that is restricted under one of our joint venture (JV) agreements.
Other Current Assets
Other current assets, net as of December 31, 2019 and 2018 consisted of the following:
Net amounts due from joint interest partners(a)
Other current assets, net
Included in the 2019 and 2018 net amounts due from joint interest partners are allowances for doubtful accounts of $22 million and $31 million, respectively.
Accrued liabilities as of December 31, 2019 and 2018 consisted of the following:
Accrued employee-related costs
Accrued taxes other than on income
Asset retirement obligation
In the fourth quarter of 2019, we implemented operational efficiencies and an organizational redesign that reduced our workforce to approximately 1,250 employees. We recorded a related charge to other non-operating expenses of $41 million, consisting of $29 million in salary and severance expense and $12 million for other termination benefits. As of December 31, 2019, our remaining associated liability of $19 million was included in accrued employee-related costs.
Supplemental Cash Flow Information
We did not make any significant U.S. federal and state income tax payments in 2019, 2018 or 2017. Interest paid, net of capitalized amounts, totaled approximately $425 million, $433 million and $393 million for the years ended December 31, 2019, 2018 and 2017, respectively.
Non-cash financing activities during 2019 included valuing the first two tranches of a warrant to purchase 0.4 million shares of our common stock (valued at $3 million) issued in connection with a development joint venture. See Note 12 Equity for more information. Non-cash financing activities in 2018 included 2.85 million shares of common stock (valued at $51 million) issued in connection with the Elk Hills transaction. See Note 4 Acquisitions and Divestitures for more on the Elk Hills transaction.