CALIFORNIA RESOURCES CORP, 10-K filed on 2/26/2020
Annual Report
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Cover Page - USD ($)
12 Months Ended
Dec. 31, 2019
Jan. 31, 2020
Jun. 30, 2019
Cover page.      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2019    
Document Transition Report false    
Entity File Number 001-36478    
Entity Registrant Name California Resources Corp    
Entity Central Index Key 0001609253    
Current Fiscal Year End Date --12-31    
Document Fiscal Year Focus 2019    
Document Fiscal Period Focus FY    
Amendment Flag false    
Entity Incorporation, State or Country Code DE    
Entity Tax Identification Number 46-5670947    
Entity Address, Address Line One 27200 Tourney Road,    
Entity Address, Address Line Two  Suite 200    
Entity Address, City or Town Santa Clarita,    
Entity Address, State or Province CA    
Entity Address, Postal Zip Code 91355    
City Area Code 888    
Local Phone Number 848-4754    
Title of 12(b) Security Common Stock    
Trading Symbol CRC    
Security Exchange Name NYSE    
Entity Well-known Seasoned Issuer No    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Large Accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
Entity Shell Company false    
Entity Public Float     $ 945,000,000
Entity Common Stock, Shares Outstanding   49,175,843  
Documents Incorporated by Reference
Portions of the registrant’s definitive proxy statement to be filed with the Securities and Exchange Commission in connection with the registrant's 2020 Annual Meeting of Stockholders, are incorporated by reference into Part III of this Form 10-K.
   
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Consolidated Balance Sheets - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
CURRENT ASSETS    
Cash $ 17 $ 17
Trade receivables 277 299
Inventories 67 69
Other current assets, net 130 255
Total current assets 491 640
PROPERTY, PLANT AND EQUIPMENT 22,889 22,523
Accumulated depreciation, depletion and amortization (16,537) (16,068)
Total property, plant and equipment, net 6,352 6,455
OTHER ASSETS 115 63
TOTAL ASSETS 6,958 7,158
CURRENT LIABILITIES    
Current maturities of long-term debt 100 0
Accounts payable 296 390
Accrued liabilities 313 217
Total current liabilities 709 607
LONG-TERM DEBT 4,877 5,251
DEFERRED GAIN AND ISSUANCE COSTS, NET 146 216
OTHER LONG-TERM LIABILITIES 720 575
MEZZANINE EQUITY    
Redeemable noncontrolling interests 802 756
EQUITY    
Preferred stock (20 million shares authorized at $0.01 par value); no shares outstanding at December 31, 2019 or 2018 0 0
Common stock (200 million shares authorized at $0.01 par value); 49,175,843 shares outstanding at December 31, 2019, 48,650,420 shares outstanding at December 31, 2018 0 0
Additional paid-in capital 5,004 4,987
Accumulated deficit (5,370) (5,342)
Accumulated other comprehensive loss (23) (6)
Total equity attributable to common stock (389) (361)
Noncontrolling interests 93 114
Total equity (296) (247)
TOTAL LIABILITIES AND EQUITY $ 6,958 $ 7,158
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Consolidated Balance Sheets (Parenthetical) - $ / shares
Dec. 31, 2019
Dec. 31, 2018
Statement of Financial Position [Abstract]    
Preferred stock, authorized shares 20,000,000 20,000,000
Preferred stock, par value (in dollars per share) $ 0.01 $ 0.01
Preferred stock, outstanding shares 0 0
Common stock, authorized shares 200,000,000 200,000,000
Common stock, par value (in dollars per share) $ 0.01 $ 0.01
Common stock, outstanding shares 49,175,843 48,650,420
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Consolidated Statements of Operations - USD ($)
$ in Millions
12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
REVENUES      
Oil and natural gas sales $ 2,270 $ 2,590 $ 1,936
Net derivative (loss) gain from commodity contracts (59) 1 (90)
Other revenue 423 473 160
Total revenues 2,634 3,064 2,006
COSTS      
Production costs 895 912 876
General and administrative expenses 290 299 249
Depreciation, depletion and amortization 471 502 544
Taxes other than on income 157 149 136
Exploration expense 29 34 22
Other expenses, net 363 399 106
Total costs 2,205 2,295 1,933
OPERATING INCOME 429 769 73
NON-OPERATING (LOSS) INCOME      
Interest and debt expense, net (383) (379) (343)
Net gain on early extinguishment of debt 126 57 4
Gain on asset divestitures 0 5 21
Other non-operating expenses (72) (23) (17)
INCOME (LOSS) BEFORE INCOME TAXES 100 429 (262)
Income tax provision (1) 0 0
NET INCOME (LOSS) 99 429 (262)
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS      
Mezzanine equity (117) (99) 0
Equity (10) (2) (4)
Net income attributable to noncontrolling interests (127) (101) (4)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK $ (28) $ 328 $ (266)
Net (loss) income attributable to common stock per share      
Basic (in dollars per share) $ (0.57) $ 6.77 $ (6.26)
Diluted (in dollars per share) $ (0.57) $ 6.77 $ (6.26)
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Consolidated Statements of Comprehensive Income - USD ($)
$ in Millions
12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Statement of Comprehensive Income [Abstract]      
Net income (loss) $ 99 $ 429 $ (262)
Net income attributable to noncontrolling interests (127) (101) (4)
Other comprehensive income (loss) items:      
Reclassification of unrealized gains (losses) on pension and postretirement losses [1] (24) 13 (14)
Reclassification of realized losses on pension and postretirement to income [1] 7 4 5
Total other comprehensive income (loss) (17) 17 (9)
Comprehensive (loss) income attributable to common stock $ (45) $ 345 $ (275)
[1] No associated tax for 2019, 2018 and 2017. See Part II, Item 8 Financial Statements and Supplementary Data, Note 14 Pension and Postretirement Benefit Plans for additional information.
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Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($)
12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Statement of Comprehensive Income [Abstract]      
Pension and postretirement losses, tax $ 0 $ 0 $ 0
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Consolidated Statements of Equity - USD ($)
$ in Millions
Total
Additional Paid-in Capital
Accumulated (Deficit) Earnings
Accumulated Other Comprehensive (Loss) Income
Equity Attributable to Common Stock
Equity Attributable to Noncontrolling Interests
Beginning balance at Dec. 31, 2016 $ (557) $ 4,861 $ (5,404) $ (14) $ (557)  
Increase (decrease) in Equity            
Net (loss) income (262)   (266)   (266) $ 4
Contribution from noncontrolling interest holders, net 98         98
Distributions paid to noncontrolling interest holders (8)         (8)
Other comprehensive income (loss) (9)     (9) (9)  
Share-based compensation, net 18 18     18  
Ending balance at Dec. 31, 2017 (720) 4,879 (5,670) (23) (814) 94
Increase (decrease) in Equity            
Net (loss) income 330   328   328 2
Contribution from noncontrolling interest holders, net 82         82
Distributions paid to noncontrolling interest holders (64)         (64)
Issuance of common stock [1] 101 101     101  
Other comprehensive income (loss) 17     17 17  
Share-based compensation, net 7 7     7  
Ending balance at Dec. 31, 2018 (247) 4,987 (5,342) (6) (361) 114
Increase (decrease) in Equity            
Net (loss) income (18)   (28)   (28) 10
Contribution from noncontrolling interest holders, net 49         49
Distributions paid to noncontrolling interest holders (80)         (80)
Other comprehensive income (loss) (17)     (17) (17)  
Warrant 3 3     3  
Share-based compensation, net 14 14     14  
Ending balance at Dec. 31, 2019 $ (296) $ 5,004 $ (5,370) $ (23) $ (389) $ 93
[1]
Includes 2.85 million shares of common stock (valued at $51 million at issuance) issued to Chevron in connection with our acquisition of Chevron's working interest in the Elk Hills unit and 2.3 million shares of common stock (valued at $50 million at issuance) issued to an Ares-led investor group. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Acquisitions and Divestitures and Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Joint Ventures for more information.
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Consolidated Statements of Equity (Parenthetical)
shares in Thousands, $ in Millions
12 Months Ended
Dec. 31, 2018
USD ($)
shares
Value of common stock at issuance $ 101 [1]
Chevron  
Common stock shares issued (in shares) | shares 2,850
Value of common stock at issuance $ 51
Ares-led investor group | Ares JV  
Common stock shares issued (in shares) | shares 2,300
Purchase price of the CRC shares issued to Ares-led investor group in a private placement $ 50
[1]
Includes 2.85 million shares of common stock (valued at $51 million at issuance) issued to Chevron in connection with our acquisition of Chevron's working interest in the Elk Hills unit and 2.3 million shares of common stock (valued at $50 million at issuance) issued to an Ares-led investor group. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Acquisitions and Divestitures and Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Joint Ventures for more information.
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Consolidated Statements of Cash Flows - USD ($)
$ in Millions
12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
CASH FLOW FROM OPERATING ACTIVITIES      
Net income (loss) $ 99 $ 429 $ (262)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:      
Depreciation, depletion and amortization 471 502 544
Net derivative loss (gain) from commodity contracts 59 (1) 90
Net proceeds (payments) on settled commodity derivatives 111 (228) (7)
Net gain on early extinguishment of debt (126) (57) (4)
Amortization of deferred gain (70) (76) (74)
Gain on asset divestitures 0 (5) (21)
Other non-cash charges to income, net 131 97 77
Dry hole expenses 7 16 2
Changes in operating assets and liabilities, net:      
Decrease (increase) in trade receivables 22 (23) (45)
(Increase) decrease in inventories 0 (6) 2
Increase in other current assets (1) (9) (2)
Decrease in accounts payable and accrued liabilities (27) (178) (52)
Net cash provided by operating activities 676 461 248
CASH FLOW FROM INVESTING ACTIVITIES      
Capital investments (455) (690) (371)
Changes in capital investment accruals (85) 69 27
Asset divestitures 164 18 33
Acquisitions (6) (547) 0
Other (12) (6) (2)
Net cash used in investing activities (394) (1,156) (313)
CASH FLOW FROM FINANCING ACTIVITIES      
Proceeds from 2014 Revolving Credit Facility 2,330 2,823 1,696
Repayments of 2014 Revolving Credit Facility (2,353) (2,646) (2,180)
Proceeds from 2017 Term Loan 0 0 1,274
Payments on 2014 Term Loan 0 0 (650)
Debt repurchases (156) (199) (116)
Debt transaction costs (2) (4) (42)
Contributions from noncontrolling interest holders, net 49 796 98
Distributions paid to noncontrolling interest holders (151) (121) (8)
Issuance of common stock 4 54 3
Shares canceled for taxes (3) (11) (2)
Net cash (used) provided by financing activities (282) 692 73
(Decrease) increase in cash 0 (3) 8
Cash—beginning of year 17 20 12
Cash—end of year $ 17 $ 17 $ 20
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NATURE OF BUSINESS, SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER
12 Months Ended
Dec. 31, 2019
NATURE OF BUSINESS, SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER  
NATURE OF BUSINESS, SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER 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

Revenue Recognition

We recognize revenue in accordance with ASC 606, Revenue from Contracts with Customers, which is more fully described in Note 15 Revenue Recognition.

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 market. Inventories as of December 31, 2019 and 2018 consisted of the following:
 
2019
 
2018
 
(in millions)
Materials and supplies
$
64

 
$
65

Finished goods
3

 
4

Total
$
67

 
$
69



Derivative Instruments

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
December 31,
 
2019
 
2018
 
(in millions)
Beginning balance
$
433

 
$
422

Liabilities incurred, capitalized to PP&E
(5
)
 
4

Liabilities settled and paid
(26
)
 
(15
)
Accretion expense
36

 
27

Acquisitions, capitalized to PP&E(a)

 
8

Dispositions, reduction to PP&E
(10
)
 
(1
)
Other
4

 
(1
)
Revisions
85

 
(11
)
Ending balance
$
517

 
$
433

(a)
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.

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 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

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:
 
2019
 
2018
 
(in millions)
Net amounts due from joint interest partners(a)
70

 
68

Derivative assets
39

 
168

Prepaid expenses
19

 
16

Other
2

 
3

Other current assets, net
$
130

 
$
255


(a)
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

Accrued liabilities as of December 31, 2019 and 2018 consisted of the following:
 
2019
 
2018
 
(in millions)
Accrued employee-related costs
$
116

 
$
109

Accrued taxes other than on income
57

 
38

Asset retirement obligation
28

 
31

Accrued interest
13

 
15

Lease liability
28

 

Other
71

 
24

Accrued liabilities
$
313

 
$
217



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.
v3.19.3.a.u2
ACCOUNTING AND DISCLOSURE CHANGES
12 Months Ended
Dec. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]  
ACCOUNTING AND DISCLOSURE CHANGES ACCOUNTING AND DISCLOSURE CHANGES

Recently Adopted Accounting and Disclosure Changes

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. Under the modified retrospective approach, we recognized right-of-use (ROU) assets and lease liabilities of $66 million as of the adoption date. 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. The new lease standard does not affect our liquidity and has no impact on our debt-covenant calculations under our 2014 Revolving Credit Facility, 2016 Credit Agreement and 2017 Credit Agreement. See Note 7 Leases for more information.
v3.19.3.a.u2
PROPERTY, PLANT AND EQUIPMENT
12 Months Ended
Dec. 31, 2019
Property, Plant and Equipment [Abstract]  
PROPERTY, PLANT AND EQUIPMENT PROPERTY, PLANT AND EQUIPMENT

The carrying value of our PP&E represents the cost incurred to acquire or develop the asset, including any ARO and capitalized interest, net of accumulated DD&A and any impairment charges. For assets acquired, initial PP&E cost is based on fair values at the acquisition date. ARO are capitalized and recovered over the lives of the related assets. No impairment charges were recorded in 2019, 2018 or 2017.

Property, plant and equipment, net as of December 31, 2019 and 2018 consisted of the following:
 
2019
 
2018
 
(in millions)
Proved oil and natural gas properties
$
21,285

 
$
20,882

Unproved oil and natural gas properties(a)
1,055

 
1,103

Facilities and other
549

 
538

     Total property, plant and equipment
22,889

 
22,523

Accumulated depreciation, depletion and amortization
(16,537
)
 
(16,068
)
Total property, plant and equipment, net
$
6,352

 
$
6,455


(a)
Includes accumulated valuation allowance for total unproved properties of $823 million and $819 million at December 31, 2019 and 2018, respectively.

The following table summarizes the activity of capitalized exploratory well costs for the years ended December 31:
 
2019
 
2018
 
2017
 
(in millions)
Balance, beginning of year
$
5

 
$
4

 
$
4

Additions to capitalized exploratory well costs
12

 
19

 
4

Reclassification to property, plant and equipment
(3
)
 
(2
)
 
(2
)
Charged to expense
(7
)
 
(16
)
 
(2
)
Balance, end of year
$
7

 
$
5

 
$
4


v3.19.3.a.u2
ACQUISITIONS AND DIVESTITURES
12 Months Ended
Dec. 31, 2019
ACQUISITIONS AND DIVESTITURES  
ACQUISITIONS AND DIVESTITURES
NOTE 4    ACQUISITIONS AND DIVESTITURES

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 2020. As of December 31, 2019, 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.

The following table summarizes the total consideration, including customary closing adjustments, and the allocation of the consideration based on the fair value of the assets acquired as of the acquisition date:
Consideration:
(in millions)
Cash
$
460

Common stock issued (2.85 million shares)
51

Liabilities assumed
7

 
$
518

 
 
Identifiable assets acquired:
 
Proved properties
$
435

Other property and equipment
77

Materials and supplies
6

 
$
518



The results of operations for the Elk Hills transaction were included in our consolidated financial statements subsequent to the closing date.

Bakersfield Office Building

In April 2018, we also acquired an office building and land in Bakersfield, California for $48 million. For the initial eight months in 2018, a former owner of the building occupied most of the space as a tenant, from which we generated approximately $4 million in rental income. In December 2018, this tenant downsized the space they are leasing through December 2022, with a corresponding reduction in rent. The vacated space not used by us will be available to lease to other tenants to generate additional income. In addition, the unimproved land may be monetized in the future. Approximately $6 million of the purchase price was allocated to the in-place leases in 2018, which is included in other assets and is being amortized into other expenses, net.

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.

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 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 2018, we divested non-core assets resulting in $18 million of proceeds and a $5 million gain.
v3.19.3.a.u2
JOINT VENTURES
12 Months Ended
Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]  
JOINT VENTURES
NOTE 5
JOINT VENTURES

Noncontrolling Interests

The following table presents the changes in noncontrolling interests for our consolidated JVs (described in greater detail below), which are reported in equity and mezzanine equity on the consolidated balance sheets for the years ended December 31, 2019 and 2018:
 
Equity Attributable to Noncontrolling Interests
 
Mezzanine Equity – Redeemable Noncontrolling Interest
 
Ares JV
 
BSP JV
 
Total
 
Ares JV
 
(in millions)
Balance, December 31, 2017
$

 
$
94

 
$
94

 
$

Net (loss) income attributable to noncontrolling interests
(11
)
 
13

 
2

 
99

Contributions from noncontrolling interest holders, net
33

 
49

 
82

 
714

Distributions to noncontrolling interest holders
(7
)
 
(57
)
 
(64
)
 
(57
)
Balance, December 31, 2018
$
15

 
$
99

 
$
114

 
$
756

Net (loss) income attributable to noncontrolling interests
(7
)
 
17

 
10

 
117

Contributions from noncontrolling interest holders, net

 
49

 
49

 

Distributions to noncontrolling interest holders
(8
)
 
(72
)
 
(80
)
 
(71
)
Balance, December 31, 2019
$

 
$
93

 
$
93

 
$
802



Ares Management L.P. (Ares)

In February 2018, we entered into a midstream JV with ECR Corporate Holdings L.P. (ECR), a portfolio company of Ares Management L.P. (Ares). This JV (Ares JV) holds the Elk Hills power plant (a 550-megawatt natural gas fired power plant) and a 200 million cubic foot per day cryogenic gas processing plant. We hold 50% of the Class A common interest and 95.25% of the Class C common interest in the Ares JV. ECR holds 50% of the Class A common interest, 100% of the Class B preferred interest and 4.75% of the Class C common interest. We received $750 million in proceeds upon entering into the Ares JV, before $3 million of transaction costs.

The Class A common and Class B preferred interests held by ECR are reported as redeemable noncontrolling interest in mezzanine equity due to an embedded optional redemption feature. The Class C common interest held by ECR is reported in equity on our consolidated balance sheets.

The Ares JV is 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. The Class B preferred interest has a deferred payment feature whereby a portion of the monthly distributions may be deferred for the first three years to the fourth and fifth year. The deferred amounts accrue an additional return. Distributions to the Class B preferred interest holders are reported as a reduction to mezzanine equity on our consolidated balance sheets.

We can cause the Ares JV to redeem ECR's Class A and Class B interests, in whole, but not in part, at any time by paying $750 million for the Class B interest and $60 million for the Class A interest, plus any previously accrued but unpaid preferred distributions and a make-whole payment if the redemption happens prior to five years from inception. We have the option to extend the redemption period for up to an additional two and one-half years, in which case the interests can be redeemed for $750 million for the Class B interest and $80 million for the Class A interest, plus any previously accrued but unpaid preferred distributions and a make-whole payment if the redemption happens prior to seven and one-half years from inception. If the Ares JV does not exercise its redemption option at the end of the seven and one-half year period, ECR can either sell its Class A and Class B interests or cause the sale or lease of the Ares JV assets.

Our consolidated statements of operations reflect the full operations of our Ares JV, with ECR's share of net income reported in net income attributable to noncontrolling interests.

Additionally, in 2018, an Ares-led investor group purchased approximately 2.3 million shares of our common stock in a private placement for an aggregate purchase price of $50 million.

Benefit Street Partners (BSP)

In February 2017, we entered into a development joint venture with BSP (BSP JV) where BSP will contribute up to $250 million, subject to agreement of the parties, 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. To date, BSP funded a total of $200 million in four equal tranches, before transaction costs. 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 full operations of the BSP JV, with BSP's share of net income being reported in net income attributable to noncontrolling interests on our consolidated statements of operations.

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 $320 million, which may be increased to a total investment of $500 million, subject to the mutual agreement of the parties. The initial commitment is 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.

In connection with the Alpine JV, Colony received a warrant to purchase up to 1.25 million shares of our common stock at an exercise price of $40 per share. Colony will be entitled to exercise the warrant in tranches as funding milestones are achieved. Each tranche will have a five-year term commencing on the date on which such tranche becomes exercisable. As of December 31, 2019, 200,000 shares of our common stock were exercisable under this warrant. Colony may elect, in its sole discretion, to pay cash or to exercise the warrant on a cashless basis, pursuant to which Colony will not be required to pay cash for shares of our common stock upon exercise of the warrant but will instead receive fewer shares.

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 exchange for a 90% working interest in the related properties (MIRA JV). MIRA funded 100% of the drilling and completion costs of agreed-upon wells in the drilling program. Our 10% working interest increases to 75% if MIRA receives cash distributions equal to a predetermined threshold return. Of the initial agreed-upon capital program of $140 million, $138 million was funded through December 31, 2019. Our consolidated results reflect only our working interest share in the productive wells.
v3.19.3.a.u2
DEBT
12 Months Ended
Dec. 31, 2019
Debt Disclosure [Abstract]  
DEBT DEBT

As of December 31, 2019 and 2018, our long-term debt consisted of the following credit agreements, Second Lien Notes and Senior Notes:
 
Outstanding Principal
 
Interest Rate(a)
 
Maturity
 
Security
 
2019
 
2018
 
 
 
 
 
 
Credit Agreements
(in millions)
 
 
 
 
 
 
2014 Revolving Credit Facility
$
518

 
$
540

 
LIBOR plus 3.25%-4.00%
ABR plus 2.25%-3.00%
 
June 30, 2021
 
Shared First-Priority Lien
2017 Credit Agreement
1,300

 
1,300

 
LIBOR plus 4.75%
ABR plus 3.75%
 
December 31, 2022(b)
 
Shared First-Priority Lien
2016 Credit Agreement
1,000

 
1,000

 
LIBOR plus 10.375%
ABR plus 9.375%
 
December 31, 2021
 
First-Priority Lien
Second Lien Notes
 
 
 
 
 
 
 
 
 
Second Lien Notes
1,815

 
2,067

 
8%
 
December 15, 2022(c)
 
Second-Priority Lien
Senior Notes
 
 
 
 
 
 
 
 
 
5% Senior Notes due 2020
100

 
100

 
5%
 
January 15, 2020
 
Unsecured
5½% Senior Notes due 2021
100

 
100

 
5.5%
 
September 15, 2021
 
Unsecured
6% Senior Notes due 2024
144

 
144

 
6%
 
November 15, 2024
 
Unsecured
Total Debt
$
4,977

 
$
5,251

 
 
 
 
 
 
Less: Current Maturities
(100
)
 

 
 
 
 
 
 
Long-Term Debt
4,877

 
5,251

 
 
 
 
 
 
(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.
(b)
The 2017 Credit Agreement is subject to a springing maturity of 91 days prior to the maturity of our 2016 Credit Agreement if more than $100 million in principal of the 2016 Credit Agreement is outstanding at that time.
(c)
The Second Lien Notes require principal repayments of approximately $287 million in June 2021, $57 million in December 2021 and $59 million in June 2022 and $1,412 million in December 2022.

Credit Agreements

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 currently consists of a $1 billion senior revolving loan facility (2014 Revolving Credit Facility), which we are permitted to increase by up to $50 million if we obtain additional commitments from new or existing lenders.

As of December 31, 2019, we had approximately $317 million of available borrowing capacity, before a $150 million month-end minimum liquidity requirement. Our 2014 Revolving Credit Facility also includes a sub-limit of $400 million for the issuance of letters of credit. As of December 31, 2019 and 2018, we had letters of credit of approximately $165 million and $162 million, respectively. These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

Security – The lenders share 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.

Interest Rate – We can elect to borrow at either LIBOR or an alternate base rate (ABR), in each case 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’s prime rate and (iii) the one-month LIBOR rate plus 1.00%. The applicable margin is adjusted based on the borrowing base utilization percentage under the 2014 Revolving Credit Facility and will 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 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 2014 Revolving Credit Facility matures on June 30, 2021.

Amortization Payments – The 2014 Revolving Credit Facility does not include any obligation to make amortization payments.

Borrowing Base – The borrowing base is redetermined each May 1 and November 1 and was most recently reaffirmed at $2.3 billion in November 2019. The borrowing base is based upon a number of factors, including commodity prices and reserves, declines in which could cause our borrowing base to be reduced. Increases in our borrowing base require approval of at least 80% of our lenders while decreases or affirmations require a two-thirds approval, in each case as measured by relative commitment amount. We and the lenders (requiring a request from the lenders holding two-thirds of the commitments) each may request a special redetermination once in any period between three consecutive scheduled redeterminations. We will be permitted to have collateral released when both (i) our credit ratings are at least Baa3 from Moody's and BBB- from S&P, in each case with a stable or better outlook, and (ii) certain permitted liens securing other debt are released.

Financial Covenants – As of December 31, 2019, our financial performance covenants included a monthly minimum liquidity requirement of not less than $150 million and the following:
Ratio
 
Components(a)
 
Required Levels
 
Tested
Maximum leverage ratio
 
Ratio of indebtedness under our 2014 Revolving Credit Facility to trailing four-quarter Adjusted EBITDAX
 
Not greater than 1.90 to 1.00 through 2019
Not greater than 1.50 to 1.00 after 2019
 
Quarterly
Minimum interest coverage ratio
 
Ratio of Adjusted EBITDAX to consolidated cash interest charges
 
Not less than 1.20 to 1.00
 
Quarterly
Minimum asset coverage ratio
 
Ratio of PV-10 to first lien indebtedness
 
Not less than 1.20 to 1.00
 
Quarterly
(a)
Refer to the terms of our credit agreements for more detailed descriptions of the components of our financial covenants.

Other Covenants – Our 2014 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 from paying cash dividends on our stock. Generally, these covenants include exceptions that allow us to pursue some of these activities in certain circumstances. In addition to these covenants, we must also apply cash on hand in excess of $150 million daily to repay amounts outstanding. Finally, we are also subject to a cross-default provision that causes a default under this facility if certain defaults occur under any of our other credit agreements or bond indentures.

Except for dispositions to development JVs, we must generally apply all of the proceeds from the sale of assets included in our borrowing base to repay loans outstanding under our 2014 Revolving Credit Facility. With respect to the sale of non-borrowing base assets (other than the Elk Hills power plant), we must apply the net cash proceeds to repay outstanding loans as follows:

25% of such proceeds for all net cash proceeds received up to $500 million
50% of such proceeds for all net cash proceeds received between $500 million and $1 billion
75% of such proceeds for all net cash proceeds received in excess of $1 billion.

We are permitted to use the balance of proceeds from non-borrowing base asset sales for general corporate purposes including acquisitions and to repurchase our Second Lien Notes and Senior Notes subject to certain conditions, including pro-forma compliance with our financial performance covenants and that we have minimum liquidity of $300 million following such repurchase.

Events of Default and Change of Control – Our 2014 Revolving Credit Facility provides for certain events of default, including upon a change of control, that entitle our lenders to declare the outstanding loans immediately due and payable, subject to certain limitations and conditions.

Recent Amendments – Our 2014 Revolving Credit Facility was most recently amended in August 2019 to provide us with flexibility in connection with potential royalty transactions.

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). The net proceeds were used to pay the $559 million remaining balance of our term loan under our 2014 Revolving Credit Facility (2014 Term Loan), resulting in a loss on the early extinguishment of debt of $8 million, reduce the balance of our 2014 Revolving Credit Facility and pay accrued interest. The proceeds received were net of a $26 million original issue discount and $38 million in transaction costs. As of December 31, 2019, we had a $1.3 billion term loan outstanding under our 2017 Credit Agreement.

Security – Our 2017 Credit Agreement is secured by the same shared first-priority lien used to secure our 2014 Revolving Credit Facility.

Maturity Date The loans mature on 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. Prepayment more than 90 days prior to maturity is subject to a 2% premium.

Financial and Other Covenants – We are 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 provides for customary covenants and events of default consistent with, or generally less restrictive than, the covenants in our 2014 Revolving Credit Facility. The covenants include limitations on additional indebtedness, liens, asset dispositions and investments, among others, and are in each case subject to certain limitations and exceptions. We are also restricted from paying cash dividends on our stock.

Events of Default and Change of Control – Our 2017 Credit Agreement provides for certain events of default, including upon a change of control, that entitle our lenders to declare the outstanding loans immediately due and payable, subject to certain limitations and conditions. We are also subject to a cross-default provision that causes a default under this credit agreement if certain defaults occur under any of our other credit agreements or indentures.

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). The net proceeds from the 2016 Credit Agreement were used to (i) prepay $250 million of our 2014 Term Loan and (ii) reduce our 2014 Revolving Credit Facility by $740 million. The proceeds received were net of a $10 million original issue discount. As of December 31, 2019, we had a $1 billion term loan outstanding under our 2016 Credit Agreement.

Security – Our 2016 Credit Agreement is 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 is second in collateral recovery to our 2014 Revolving Credit Facility and 2017 Credit Agreement.

Maturity Date – The loans mature on December 31, 2021. Prepayment is subject to a variable make-whole amount prior to the fourth anniversary. Following the fourth anniversary, we may redeem at par.

Financial and Other Covenants – We are 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 includes other covenants that are substantially similar to our 2017 Credit Agreement. We are also restricted from paying cash dividends on our stock.

Events of Default and Change of Control – Our 2016 Credit Agreement provides for certain events of default, including upon a change of control, that entitle our lenders to declare the outstanding loans immediately due and payable, subject to certain limitations and conditions. We are also subject to a cross-default provision that causes a default under this credit agreement if certain defaults occur under any of our other credit agreements or indentures.

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 is being amortized using the effective interest rate method over the term of our Second Lien Notes. We pay cash interest semiannually in arrears on June 15 and December 15.

Security – Our Second Lien Notes are 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.

Repurchases – 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. In 2018, we repurchased $183 million in face value of our Second Lien Notes for $159 million in cash, resulting in a pre-tax gain of $48 million including the effect of unamortized deferred gain and issuance costs.

Financial and Other Covenants – The indenture includes covenants that, among other things, limit 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 covenants are not, however, directly linked to measures of our financial performance. In addition, if we experience a “change of control triggering event” (as defined in the indenture), we will be required, unless we have exercised our right to redeem our Second Lien Notes, to offer to purchase our Second Lien Notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest. The indenture also restricts our ability to sell certain assets and to release collateral from liens securing our Second Lien Notes, unless the collateral is also released in compliance with our senior credit facilities. We are also subject to a cross-default provision that causes a default under this indenture if certain defaults occur under any of our other credit agreements or indentures.

Redemption – We may redeem our Second Lien Notes (i) prior to December 15, 2018, in whole or in part at a redemption price equal to 100% of the principal amount redeemed plus a make-whole amount and accrued and unpaid interest, (ii) between December 15, 2018 and 2020, in whole or in part at a fixed redemption price ranging from 104% to 102% of the principal amount redeemed plus accrued and unpaid interest and (iii) thereafter in whole or in part at a redemption price equal to 100% of the principal amount redeemed plus accrued and unpaid interest.

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.

Repurchases – In 2019, we did not repurchase any of our Senior Notes. In 2018, we repurchased $49 million in face value of our 2024 Notes for $40 million in cash, resulting in a pre-tax gain of $9 million including the effect of unamortized deferred issuance costs.

Financial and Other Covenants – The indenture includes covenants that, among other things, limit 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 covenants are not, however, directly linked to measures of our financial performance. In addition, if we experience a “change of control triggering event” (as defined in the indenture), we will be required, unless we have exercised our right to redeem our Senior Notes, to offer to purchase our Senior Notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest. We are also subject to a cross-default provision that causes a default under this indenture if certain defaults occur under any of our other credit agreements or indentures.

Redemption – We may redeem our Senior Notes prior to their maturity dates, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed plus accrued and unpaid interest and, generally, a make-whole amount.

Deferred Gain and Issuance Costs

At December 31, 2019 and 2018, net deferred gain and issuance costs consisted of the following:
 
2019
 
2018
 
(in millions)
Deferred gain
$
211

 
$
313

Deferred issuance costs and original issue discounts
(65
)
 
(97
)
Net deferred gain and issuance costs
$
146

 
$
216



Other

At December 31, 2019, we were in compliance with all financial and other debt covenants.

All obligations under our 2014 Revolving Credit Facility, 2017 Credit Agreement and 2016 Credit Agreement (collectively, Credit Facilities) as well as our Second Lien Notes and Senior Notes are guaranteed both fully and unconditionally and jointly and severally by all 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.

Principal maturities of debt outstanding at December 31, 2019 are as follows:
 
As of
December 31, 2019
 
(in millions)
2020
$
100

2021
1,962

2022
2,771

2023

2024
144

Thereafter

Total
$
4,977



We estimate the fair value of fixed-rate debt, which is classified as Level 1, based on prices from known market transactions for our instruments. The estimated fair value of our debt at December 31, 2019 and 2018, including the fair value of the variable-rate portion, was approximately $3.8 billion and $4.5 billion, respectively, compared to a face value of approximately $5.0 billion and $5.3 billion, respectively.
v3.19.3.a.u2
LEASES
12 Months Ended
Dec. 31, 2019
Leases [Abstract]  
LEASES LEASES

On January 1, 2019, we adopted ASC 842 using the modified retrospective approach that required us to determine our lease balances as of that date. Prior periods continue to be reported under accounting standards in effect for those periods. We elected to carry forward our accounting treatment for land easements on existing agreements. Mineral leases, including oil and natural gas leases, are not included within the scope of ASC 842.

We have long-term operating leases for commercial office space, drilling rigs, fleet vehicles and certain facilities. 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 as of the date of adoption 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 elected to combine lease and non-lease components in determining fixed minimum lease payments for our drilling rigs and commercial office space. If applicable, fixed minimum lease payments were reduced by lease incentives for our commercial buildings and increased by mobilization and demobilization fees related to 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.

For all of our asset classes, we elected to keep leases with an initial term of 12 months or less off the balance sheet and have included costs related to these contracts in our short-term lease cost disclosure below. Contracts with terms of one month or less are excluded from our disclosure of short-term lease costs.

For our long-term contracts, variable lease costs were not included in the measurement of our lease balances. Variable lease costs for our drilling rigs included 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 operating lease costs, including amounts capitalized to PP&E, for the year ended December 31, 2019 were as follows:
 
2019
 
(in millions)
Operating lease cost
$
52

Short-term lease cost
74

Variable lease cost(a)
21

Total operating lease costs
$
147

(a)
Includes $19 million related to drilling rigs, which are capitalized to PP&E.

During the second quarter of 2019, we entered into 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. For the year ended December 31, 2019, sublease income was not material to our consolidated financial statements.
Cash flows related to our operating leases for the year ended December 31, 2019 were as follows:
 
2019
 
(in millions)
Operating cash flows
$
14

Investing cash flows
$
40



Our cash flows related to finance leases were not significant for the year ended December 31, 2019.
Other information related to our operating and finance leases as of December 31, 2019 was as follows:
 
2019
Operating Leases
 
ROU asset obtained in exchange for lease obligations (in millions)
$
122

Weighted-average remaining lease term (in years)
4.75

Weighted-average discount rate
12.2
%
 
 
Finance Leases
 
ROU asset obtained in exchange for lease obligations (in millions)
$
2

Weighted-average remaining lease term (in years)
2.33

Weighted-average discount rate
8.5
%


The difference in the weighted-average discount rate between operating leases and finance leases primarily relates to lease term.

Balance sheet information related to our operating and finance leases as of December 31, 2019 was as follows:
 
Balance Sheet Location
 
2019
Assets
 
 
(in millions)
Operating lease, net
Other assets
 
$
59

Finance lease, net
PP&E
 
2

Total lease assets
 
 
$
61

 
 
 
 
Liabilities
 
 
 
Current
 
 
 
   Operating lease
Accrued liabilities
 
$
27

   Finance lease
Accrued liabilities
 
1

Long-term
 
 
 
   Operating lease
Other long-term liabilities
 
37

   Finance lease
Other long-term liabilities
 
1

Total lease liabilities
 
 
$
66



As part of our company-wide consolidation of office space, we vacated certain office space in 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. For the year ended December 31, 2019, we recognized impairment charges of $3 million related to our leases and $6 million related to abandoned tenant improvements. 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 shortened the useful life of the ROU assets and related tenant improvements to recover our remaining costs over our expected period of use. Once the leased office space is vacated, lease costs will be classified as other non-operating expenses on our consolidated statements of operations.

Maturities of our operating and finance lease liabilities at December 31, 2019 are as follows:
 
Operating
 
Finance
 
Leases
 
Leases
 
(in millions)
2020
$
32

 
$
1

2021
11

 
1

2022
9

 

2023
9

 

2024
6

 

Thereafter
23

 

Less: Interest
(26
)
 

Present value of lease liabilities
$
64

 
$
2



We entered into a contract for a facility that is under construction as of December 31, 2019. This lease is not included in our lease population at December 31, 2019 because the lease term has not commenced, and we do not control the asset during construction. We will apply the new lease standard when the asset is placed in service by us, which is expected to be in June 2020.

At December 31, 2018, future minimum lease payments for noncancelable operating leases under ASC 840 (excluding oil and natural gas and other mineral leases, utilities, taxes, insurance and common area maintenance expenses) were:
 
December 31,
 
2018
 
(in millions)
2019
$
12

2020
8

2021
7

2022
7

2023
6

Thereafter
28

Total
$
68



Rent expense for operating leases under ASC 840 was $11 million in 2018 and $13 million in 2017. Rental income from subleases for the years ended December 31, 2018 and 2017 was not significant.
LEASES LEASES

On January 1, 2019, we adopted ASC 842 using the modified retrospective approach that required us to determine our lease balances as of that date. Prior periods continue to be reported under accounting standards in effect for those periods. We elected to carry forward our accounting treatment for land easements on existing agreements. Mineral leases, including oil and natural gas leases, are not included within the scope of ASC 842.

We have long-term operating leases for commercial office space, drilling rigs, fleet vehicles and certain facilities. 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 as of the date of adoption 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 elected to combine lease and non-lease components in determining fixed minimum lease payments for our drilling rigs and commercial office space. If applicable, fixed minimum lease payments were reduced by lease incentives for our commercial buildings and increased by mobilization and demobilization fees related to 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.

For all of our asset classes, we elected to keep leases with an initial term of 12 months or less off the balance sheet and have included costs related to these contracts in our short-term lease cost disclosure below. Contracts with terms of one month or less are excluded from our disclosure of short-term lease costs.

For our long-term contracts, variable lease costs were not included in the measurement of our lease balances. Variable lease costs for our drilling rigs included 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 operating lease costs, including amounts capitalized to PP&E, for the year ended December 31, 2019 were as follows:
 
2019
 
(in millions)
Operating lease cost
$
52

Short-term lease cost
74

Variable lease cost(a)
21

Total operating lease costs
$
147

(a)
Includes $19 million related to drilling rigs, which are capitalized to PP&E.

During the second quarter of 2019, we entered into 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. For the year ended December 31, 2019, sublease income was not material to our consolidated financial statements.
Cash flows related to our operating leases for the year ended December 31, 2019 were as follows:
 
2019
 
(in millions)
Operating cash flows
$
14

Investing cash flows
$
40



Our cash flows related to finance leases were not significant for the year ended December 31, 2019.
Other information related to our operating and finance leases as of December 31, 2019 was as follows:
 
2019
Operating Leases
 
ROU asset obtained in exchange for lease obligations (in millions)
$
122

Weighted-average remaining lease term (in years)
4.75

Weighted-average discount rate
12.2
%
 
 
Finance Leases
 
ROU asset obtained in exchange for lease obligations (in millions)
$
2

Weighted-average remaining lease term (in years)
2.33

Weighted-average discount rate
8.5
%


The difference in the weighted-average discount rate between operating leases and finance leases primarily relates to lease term.

Balance sheet information related to our operating and finance leases as of December 31, 2019 was as follows:
 
Balance Sheet Location
 
2019
Assets
 
 
(in millions)
Operating lease, net
Other assets
 
$
59

Finance lease, net
PP&E
 
2

Total lease assets
 
 
$
61

 
 
 
 
Liabilities
 
 
 
Current
 
 
 
   Operating lease
Accrued liabilities
 
$
27

   Finance lease
Accrued liabilities
 
1

Long-term
 
 
 
   Operating lease
Other long-term liabilities
 
37

   Finance lease
Other long-term liabilities
 
1

Total lease liabilities
 
 
$
66



As part of our company-wide consolidation of office space, we vacated certain office space in 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. For the year ended December 31, 2019, we recognized impairment charges of $3 million related to our leases and $6 million related to abandoned tenant improvements. 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 shortened the useful life of the ROU assets and related tenant improvements to recover our remaining costs over our expected period of use. Once the leased office space is vacated, lease costs will be classified as other non-operating expenses on our consolidated statements of operations.

Maturities of our operating and finance lease liabilities at December 31, 2019 are as follows:
 
Operating
 
Finance
 
Leases
 
Leases
 
(in millions)
2020
$
32

 
$
1

2021
11

 
1

2022
9

 

2023
9

 

2024
6

 

Thereafter
23

 

Less: Interest
(26
)
 

Present value of lease liabilities
$
64

 
$
2



We entered into a contract for a facility that is under construction as of December 31, 2019. This lease is not included in our lease population at December 31, 2019 because the lease term has not commenced, and we do not control the asset during construction. We will apply the new lease standard when the asset is placed in service by us, which is expected to be in June 2020.

At December 31, 2018, future minimum lease payments for noncancelable operating leases under ASC 840 (excluding oil and natural gas and other mineral leases, utilities, taxes, insurance and common area maintenance expenses) were:
 
December 31,
 
2018
 
(in millions)
2019
$
12

2020
8

2021
7

2022
7

2023
6

Thereafter
28

Total
$
68



Rent expense for operating leases under ASC 840 was $11 million in 2018 and $13 million in 2017. Rental income from subleases for the years ended December 31, 2018 and 2017 was not significant.
v3.19.3.a.u2
LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES
12 Months Ended
Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]  
LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES 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, 2019 and 2018 were not material to our consolidated balance sheets as of such dates. 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 accrued would not be material to our consolidated financial position or results of operations.
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, 2019, total purchase obligations on a discounted basis were as follows:
 
December 31, 2019
 
(in millions)
2020
$
88

2021
16

2022
8

2023
14

2024
5

Thereafter
22

Total
153

Less: Interest
(24
)
Present value of purchase obligations
$
129


We remain subject to audit by the Internal Revenue Service for calendar years 2016 through 2018 as well as 2015 through 2018 by the state of California.
v3.19.3.a.u2
DERIVATIVES
12 Months Ended
Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
DERIVATIVES
NOTE 9    DERIVATIVES

We use a variety of derivative instruments to protect our cash flow, operating margin and capital program from the cyclical nature of commodity prices and interest-rate movements. These derivatives are intended to help us maintain adequate liquidity and improve our ability to comply with the covenants of our Credit Facilities in case of commodity-price deterioration.

Commodity-Price Risk

We did not have any commodity derivatives designated as accounting hedges as of and during the years ended December 31, 2019, 2018 and 2017. As part of our hedging program, we held the following Brent-based crude oil contracts as of December 31, 2019:
 
Q1
2020
 
Q2
2020
 
Q3
2020
 
Q4
2020
Purchased Puts:
 
 
 
 
 
 
 
Barrels per day
30,000

 
20,000

 
13,000

 
8,000

Weighted-average price per barrel
$
70.83

 
$
67.50

 
$
65.00

 
$
65.00

 
 
 
 
 
 
 
 
Sold Puts:
 
 
 
 
 
 
 
Barrels per day
30,000

 
20,000

 
18,000

 
13,000

Weighted-average price per barrel
$
56.67

 
$
53.75

 
$
54.31

 
$
53.81

 
 
 
 
 
 
 
 
Swaps:
 
 
 
 
 
 
 
Barrels per day

 
5,000

 
5,000

 
5,000

Weighted-average price per barrel
$

 
$
70.05

 
$
65.00

 
$
65.00



Our counterparties have an option to increase volumes by up to 5,000 barrels per day for the second quarter of 2020 at a weighted-average Brent price of $70.05. A counterparty has an option to increase volumes by up to 5,000 barrels per day for the second half of 2020 at a weighted-average Brent price of $65.00.

The BSP JV entered into crude oil derivatives that are included in our consolidated results but not in the above table. The hedges entered into by the BSP JV could affect the timing of the reversion of BSP's preferred interest. The BSP JV sold call options for approximately 500 barrels per day at a weighted-average price per barrel of $60.00 per barrel for 2020. The BSP JV purchased put options for approximately 2,000 barrels per day at a weighted-average price per barrel of approximately $50.00 for 2020. The BSP JV also purchased put options for approximately 1,000 barrels per day at a weighted-average price per barrel of approximately $45.00 for 2021. The BSP JV also entered into natural gas swaps for insignificant volumes for periods through May 2021.

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.

From time to time, we may use combinations of these positions to increase the efficacy of our hedging program.

For the years ended December 31, 2019, 2018 and 2017, we recorded a non-cash derivative (loss) gain of approximately $(170) million, $229 million, and $(83) million, respectively, from marking these contracts to market, which were included in net derivative (loss) gain from commodity contracts on our consolidated statements of operations. For the year ended December 31, 2019, we received settlement payments of $111 million. For the years ended December 31, 2018 and 2017, we made settlement payments of $228 million and $7 million, respectively.

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 years ended December 31, 2019 and 2018, we reported losses on these contracts in other non-operating expenses on our consolidated statements of operations of $4 million and $6 million, respectively. No payments were received in either 2019 or 2018.

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 table presents the fair values (at gross and net) of our outstanding derivatives as of December 31, 2019 and 2018:
December 31, 2019
Balance Sheet Classification
 
Gross Amounts Recognized at Fair Value
 
Gross Amounts Offset in the Balance Sheet
 
Net Fair Value Presented in the Balance Sheet
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

December 31, 2018
Balance Sheet Classification
 
Gross Amounts Recognized at Fair Value
 
Gross Amounts Offset in the Balance Sheet
 
Net Fair Value Presented in the Balance Sheet
Assets:
 
(in millions)
Other current assets
 
$
252

 
$
(84
)
 
$
168

Other assets
 
23

 
(9
)
 
14

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Accrued liabilities
 
(87
)
 
84

 
(3
)
Other long-term liabilities
 
(10
)
 
9

 
(1
)
 
 
$
178

 
$

 
$
178



Interest-Rate Contracts

As of December 31, 2019, and 2018, we reported the fair value of our interest-rate derivatives of zero and $4 million, respectively, in other assets on our consolidated balance sheets.

Counterparty Credit Risk

Our credit risk relates primarily to trade receivables, joint interest receivables and derivative financial instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. We actively manage this credit risk by selecting counterparties that we believe to be financially strong and continuing to monitor their financial health. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.

As of December 31, 2019, the substantial majority of the credit exposures related to our derivative financial instruments was with investment-grade counterparties. We believe exposure to credit-related losses at December 31, 2019 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, 2019, and 2018, we had insignificant collateral posted.
v3.19.3.a.u2
INCOME TAXES
12 Months Ended
Dec. 31, 2019
Income Tax Disclosure [Abstract]  
INCOME TAXES INCOME TAXES

Income Tax Provision (Benefit)

Income (loss) before income taxes, which is all domestic, was $100 million, $429 million and $(262) million for the years ended December 31, 2019, 2018 and 2017, respectively. We did not record a significant income tax provision (benefit) in any of the years ended December 31, 2019, 2018 and 2017.

Total income tax expense (benefit) differs from the amounts computed by applying the U.S. federal income tax rate to pre-tax income (loss) as follows:
 
For the years ended
December 31,
 
2019
 
2018
 
2017
U.S. federal statutory tax rate
21
 %
 
21
 %
 
(35
)%
State income taxes, net
7

 
6

 
(6
)
Exclusion of tax attributable to noncontrolling interests, net
(35
)
 
(5
)
 

Decrease in U.S. federal corporate tax rate

 

 
91

Tax credits, net
(9
)
 
(6
)
 
(19
)
Nondeductible compensation, net
3

 

 

Stock-based compensation, net

 

 
1

Change in valuation allowance, net
14

 
(17
)
 
(33
)
Other, net

 
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 tax credits including the enhanced oil recovery credit. Our U.S. federal deferred tax assets and liabilities were remeasured due to the reduction of the top corporate tax rate from 35% to 21% under the Tax Cuts and Jobs Act (TCJA) enacted on December 22, 2017. The TCJA also included significant changes to the deduction for executive compensation by public corporations.

Given our income tax position, any item affecting our effective tax rate described above is generally offset by an equal change in the valuation allowance. Our valuation allowance increased $21 million during 2019, $16 million of which was recorded to income tax provision and $5 million was recorded to accumulated other comprehensive income. Our valuation allowance decreased $81 million in 2018, $76 million of which was recorded to income tax provision and $5 million was recorded to accumulated other comprehensive income. Our valuation allowance decreased $74 million in 2017, $78 million of which was recorded as an income tax benefit and $4 million reduced accumulated other comprehensive income.
Under the TCJA, for taxable years beginning in 2018, our deduction for business interest is limited to 30% of our adjusted taxable income. For purposes of this limitation, adjustable taxable income is computed without regard to net business interest expense and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization or depletion. Proposed Treasury Regulations issued in December 2018 provide that depreciation, amortization or depletion expense that is capitalized to inventory is not treated as depreciation, amortization or depletion for the purposes of computing adjustable taxable income. It is reasonably possible that the composition of our deferred tax assets, specifically the amount reported for net operating loss and business interest expense carryforwards, could significantly change when the Internal Revenue Service finalizes and issues regulations. Our carryforwards for business interest expense do not expire.



Deferred Tax Assets and Liabilities
The tax effects of temporary differences resulting in deferred income tax assets and liabilities at December 31, 2019 and 2018 were as follows:
 
2019
 
2018
 
Deferred Tax
Assets
 
Deferred Tax
Liabilities
 
Deferred Tax
Assets
 
Deferred Tax
Liabilities
 
(in millions)
Debt
$
176

 
$

 
$
253

 
$

Property, plant and equipment

 
(517
)
 
11

 
(316
)
Postretirement benefit accruals
40

 

 
27

 

Deferred compensation and benefits
55

 

 
56

 

Asset retirement obligations
155

 

 
129

 

Net operating loss and tax credit carryforwards
457

 

 
314

 

Business interest expense carryforward
194

 

 
82

 

Investment in partnerships
110