Document and Entity Information
Document and Entity Information Cover - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Feb. 24, 2020 | Jun. 30, 2019 | |
Entity Information [Line Items] | |||
Entity Registrant Name | CALPINE CORP | ||
Entity Central Index Key | 0000916457 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Non-accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2019 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 105.2 | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | Yes | ||
Entity Current Reporting Status | No | ||
Entity Public Float | $ 0 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Operating revenues: | ||||
Commodity revenue | $ 9,437 | $ 9,865 | $ 8,836 | |
Mark to Market Gain Loss on Derivatives included in Operating Revenues | 618 | (373) | (101) | |
Other revenue | 17 | 20 | 17 | |
Operating revenues | [1] | 10,072 | 9,512 | 8,752 |
Operating expenses: | ||||
Commodity expense | 6,164 | 6,914 | 6,268 | |
Mark to Market Gain Loss on Derivatives Included in Fuel and Purchased Energy Expense | 340 | (165) | 70 | |
Fuel and purchased energy expense | 6,504 | 6,749 | 6,338 | |
Operating and maintenance expense | 1,001 | 1,020 | 1,080 | |
Depreciation and amortization expense | 694 | 739 | 724 | |
General and other administrative expense | 150 | 158 | 155 | |
Other operating expenses | 79 | 98 | 85 | |
Total operating expenses | 8,428 | 8,764 | 8,382 | |
Impairment losses | 84 | 10 | 41 | |
(Gain) on sale of assets, net | (10) | 0 | (27) | |
(Income) from unconsolidated subsidiaries | (22) | (24) | (22) | |
Income from operations | 1,592 | 762 | 378 | |
Interest expense | 609 | 617 | 621 | |
(Gain) loss on extinguishment of debt | 58 | (28) | 38 | |
Other (income) expense, net | 37 | 81 | 32 | |
Income before income taxes | 888 | 92 | (313) | |
Income tax expense | 98 | 64 | 8 | |
Net income (loss) | 790 | 28 | (321) | |
Net income attributable to the noncontrolling interest | (20) | (18) | (18) | |
Net income (loss) attributable to Calpine | $ 770 | $ 10 | $ (339) | |
[1] | Includes intersegment revenues of $530 million, $488 million and $324 million in the West, $946 million, $573 million and $361 million in Texas, $522 million, $234 million and $237 million in the East and $11 million, $4 million, $4 million in Retail for the years ended December 31, 2019, 2018 and 2017, respectively. |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Net income (loss) | $ 790 | $ 28 | $ (321) |
Cash flow hedging activities: | |||
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss) | (42) | 40 | (22) |
Reclassification adjustment for loss on cash flow hedges realized in net income (loss) | 2 | 6 | 48 |
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax | (2) | 1 | 0 |
Foreign currency translation gain (loss) | 3 | (10) | 13 |
Income tax benefit (expense) | 2 | (5) | (6) |
Other comprehensive income (loss) | (37) | 32 | 33 |
Comprehensive income (loss) | 753 | 60 | (288) |
Comprehensive (income) attributable to the noncontrolling interest | (20) | (21) | (20) |
Comprehensive income (loss) attributable to Calpine | $ 733 | $ 39 | $ (308) |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets: | ||
Cash and cash equivalents ($33 and $43 attributable to VIEs) | $ 1,131 | $ 205 |
Accounts receivable, net of allowance of $9 and $9 | 757 | 1,022 |
Inventories ($77 and $71 attributable to VIEs) | 543 | 525 |
Margin deposits and other prepaid expense | 367 | 315 |
Restricted cash, current ($206 and $90 attributable to VIEs) | 299 | 167 |
Derivative assets, current | 156 | 142 |
Other current assets | 49 | 43 |
Total current assets | 3,302 | 2,419 |
Property, plant and equipment, net ($3,454 and $3,919 attributable to VIEs) | 11,963 | 12,442 |
Restricted cash, net of current portion ($15 and $33 attributable to VIEs) | 46 | 34 |
Investments in unconsolidated subsidiaries | 70 | 76 |
Long-term derivative assets | 246 | 160 |
Goodwill | 242 | 242 |
Finite-Lived Intangible Assets, Net | 340 | 412 |
Other assets ($53 and $30 attributable to VIEs) | 440 | 277 |
Total assets | 16,649 | 16,062 |
Current liabilities: | ||
Accounts payable | 714 | 958 |
Accrued interest payable ($7 and $10 attributable to VIEs) | 61 | 96 |
Debt, current portion ($161 and $201 attributable to VIEs) | 1,268 | 637 |
Derivative liabilities, current | 225 | 303 |
Other current liabilities ($122 and $36 attributable to VIEs) | 657 | 489 |
Total current liabilities | 2,925 | 2,483 |
Debt, net of current portion ($1,635 and $1,978 attributable to VIEs) | 10,438 | 10,148 |
Long-term derivative liabilities ($8 and $6 attributable to VIEs) | 63 | 140 |
Other long-term liabilities ($53 and $36 attributable to VIEs) | 565 | 235 |
Total liabilities | 13,991 | 13,006 |
Stockholder’s equity: | ||
Common stock, $0.001 par value per share; authorized 5,000 and 5,000 shares, respectively, 105.2 and 105.2 shares issued, respectively, and 105.2 and 105.2 shares outstanding, respectively | 0 | 0 |
Additional paid-in capital | 9,584 | 9,582 |
Accumulated deficit | (6,923) | (6,542) |
Accumulated other comprehensive loss | (114) | (77) |
Total Calpine stockholder’s equity | 2,547 | 2,963 |
Noncontrolling interest | 111 | 93 |
Total stockholder’s equity | 2,658 | 3,056 |
Total liabilities and stockholder’s equity | $ 16,649 | $ 16,062 |
Consolidated Balance Sheets Con
Consolidated Balance Sheets Consolidated Balance Sheets Parentheticals - USD ($) | Dec. 31, 2019 | Dec. 31, 2018 |
Cash and cash equivalents ($33 and $43 attributable to VIEs) | $ 1,131,000,000 | $ 205,000,000 |
Accounts receivable, net of allowance of $9 and $9 | 9,000,000 | 9,000,000 |
Inventories ($77 and $71 attributable to VIEs) | 543,000,000 | 525,000,000 |
Restricted cash, current ($206 and $90 attributable to VIEs) | 299,000,000 | 167,000,000 |
Property, plant and equipment, net ($3,454 and $3,919 attributable to VIEs) | 11,963,000,000 | 12,442,000,000 |
Restricted cash, net of current portion ($15 and $33 attributable to VIEs) | 46,000,000 | 34,000,000 |
Other assets ($53 and $30 attributable to VIEs) | 440,000,000 | 277,000,000 |
Accrued interest payable ($7 and $10 attributable to VIEs) | 61,000,000 | 96,000,000 |
Debt, current portion ($161 and $201 attributable to VIEs) | 1,268,000,000 | 637,000,000 |
Other current liabilities ($122 and $36 attributable to VIEs) | 657,000,000 | 489,000,000 |
Debt, net of current portion ($1,635 and $1,978 attributable to VIEs) | 10,438,000,000 | 10,148,000,000 |
Long-term derivative liabilities ($8 and $6 attributable to VIEs) | 63,000,000 | 140,000,000 |
Other long-term liabilities ($53 and $36 attributable to VIEs) | $ 565,000,000 | $ 235,000,000 |
Common Stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Common Stock, authorized shares (in shares) | 5,000 | 5,000 |
Common Stock, issued shares (in shares) | 105.2 | 105.2 |
Common Stock, outstanding shares (in shares) | 105.2 | 105.2 |
Treasury Stock, Shares | ||
Variable Interest Entity, Primary Beneficiary [Member] | ||
Cash and cash equivalents ($33 and $43 attributable to VIEs) | $ 33,000,000 | $ 43,000,000 |
Inventories ($77 and $71 attributable to VIEs) | 77,000,000 | 71,000,000 |
Restricted cash, current ($206 and $90 attributable to VIEs) | 206,000,000 | 90,000,000 |
Property, plant and equipment, net ($3,454 and $3,919 attributable to VIEs) | 3,454,000,000 | 3,919,000,000 |
Restricted cash, net of current portion ($15 and $33 attributable to VIEs) | 15,000,000 | 33,000,000 |
Other assets ($53 and $30 attributable to VIEs) | 53,000,000 | 30,000,000 |
Accrued interest payable ($7 and $10 attributable to VIEs) | 7,000,000 | 10,000,000 |
Debt, current portion ($161 and $201 attributable to VIEs) | 161,000,000 | 201,000,000 |
Other current liabilities ($122 and $36 attributable to VIEs) | 122,000,000 | 36,000,000 |
Debt, net of current portion ($1,635 and $1,978 attributable to VIEs) | 1,635,000,000 | 1,978,000,000 |
Long-term derivative liabilities ($8 and $6 attributable to VIEs) | 8 | 6 |
Other long-term liabilities ($53 and $36 attributable to VIEs) | $ 53 | $ 36 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders Equity - USD ($) $ in Millions | Total | Common Stock [Member] | Treasury Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings (Accumulated Deficit) [Member] | AOCI Attributable to Parent [Member] | Noncontrolling Interest [Member] |
Balance at Dec. 31, 2016 | $ 3,339 | $ 0 | $ (7) | $ 9,625 | $ (6,213) | $ (137) | $ 71 |
Treasury stock transactions | (8) | 0 | (8) | 0 | 0 | 0 | 0 |
Stock-based compensation expense | 36 | 0 | 0 | 36 | 0 | 0 | 0 |
Distribution to the noncontrolling interest | (12) | 0 | 0 | 0 | 0 | 0 | (12) |
Net income (loss) | (321) | 0 | 0 | 0 | (339) | 0 | 18 |
Other comprehensive income (loss) | 33 | 0 | 0 | 0 | 0 | 31 | 2 |
Balance at Dec. 31, 2017 | 3,067 | 0 | (15) | 9,661 | (6,552) | (106) | 79 |
Treasury stock transactions | (7) | 0 | (7) | 0 | 0 | 0 | 0 |
Stock-based compensation expense | 41 | 0 | 0 | 41 | 0 | 0 | 0 |
Effects of the Merger | (78) | 0 | 22 | (100) | 0 | 0 | 0 |
Dividends | (20) | 0 | 0 | (20) | 0 | 0 | 0 |
Contribution from the noncontrolling interest | 2 | 0 | 0 | 0 | 0 | 0 | 2 |
Distribution to the noncontrolling interest | (9) | 0 | 0 | 0 | 0 | 0 | (9) |
Net income (loss) | 28 | 0 | 0 | 0 | 10 | 0 | 18 |
Other comprehensive income (loss) | 32 | 0 | 0 | 0 | 0 | 29 | 3 |
Balance at Dec. 31, 2018 | 3,056 | 0 | 0 | 9,582 | (6,542) | (77) | 93 |
Effects of the Merger | 0 | 0 | 0 | (2) | 0 | 0 | 2 |
Dividends | 1,151 | 0 | 0 | 0 | 1,151 | 0 | 0 |
Net income (loss) | 790 | 0 | 0 | 0 | 770 | 0 | 20 |
Other comprehensive income (loss) | (37) | 0 | 0 | 0 | 0 | (37) | 0 |
Balance at Dec. 31, 2019 | $ 2,658 | $ 0 | $ 0 | $ 9,584 | $ (6,923) | $ (114) | $ 111 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||||
Cash flows from operating activities: | ||||||
Net income (loss) | $ 790 | $ 28 | $ (321) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||
Depreciation and amortization(1) | [1] | 781 | 848 | 921 | ||
(Gain) loss on extinguishment of debt | 22 | (32) | 38 | |||
Deferred income taxes | 95 | 47 | 14 | |||
Impairment losses | 84 | 10 | 41 | |||
(Gain) on sale of assets, net | (10) | 0 | (27) | |||
Mark-to-market activity, net | [2] | (275) | 205 | 169 | ||
(Income) from unconsolidated subsidiaries | (22) | (24) | (22) | |||
Return on investments from unconsolidated subsidiaries | 21 | 35 | 28 | |||
Stock-based compensation expense | 0 | 57 | 42 | |||
Other | 3 | 29 | (5) | |||
Change in operating assets and liabilities, net of effects of acquisitions: | ||||||
Accounts receivable | 265 | (101) | (108) | |||
Accounts payable | (271) | 164 | 70 | |||
Margin deposits and other prepaid expense | (57) | (134) | 115 | |||
Other assets and liabilities, net | 144 | (82) | (15) | |||
Derivative instruments, net | (14) | 51 | 9 | |||
Net cash provided by operating activities | 1,556 | 1,101 | 949 | |||
Cash flows from investing activities: | ||||||
Purchases of property, plant and equipment | (584) | (415) | (305) | |||
Proceeds from sale of power plants and other | [3] | 322 | 11 | 162 | ||
Return of investment from unconsolidated subsidiaries | 5 | 18 | 0 | |||
Other | (1) | (6) | 43 | |||
Net cash used in investing activities | (258) | (392) | (211) | |||
Cash flows from financing activities: | ||||||
Borrowings under CCFC Term Loan and First Lien Term Loans | 1,687 | 0 | 1,395 | |||
Repayments of CCFC Term Loans and First Lien Term Loans | (1,507) | (41) | (2,150) | |||
Borrowings under First Lien Notes | 1,250 | 0 | 560 | |||
Repayments of Senior Debt | (811) | 0 | 0 | |||
Proceeds from Unsecured Notes Payable | 1,400 | 0 | 0 | |||
Repayments of Senior Unsecured Notes | (768) | (355) | (453) | |||
Proceeds from Lines of Credit | 342 | 525 | 440 | |||
Repayments of Lines of Credit | (250) | (495) | (440) | |||
Borrowings from project financing, notes payable and other | 0 | 220 | 0 | |||
Repayments of project financing, notes payable and other | (404) | (470) | (174) | |||
Financing costs | (67) | (18) | (60) | |||
Stock repurchases | 0 | (79) | 0 | |||
Dividends | (1,151) | 20 | ||||
Payments of Dividends | [3] | (1,151) | (20) | 0 | ||
Other | 51 | (13) | (19) | |||
Net cash used in financing activities | (228) | (746) | (901) | |||
Net increase (decrease) in cash, cash equivalents and restricted cash | 1,070 | (37) | (163) | |||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 406 | [4] | 443 | [4] | 606 | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | [4] | 1,476 | 406 | 443 | ||
Cash paid during the period for: | ||||||
Interest, net of amounts capitalized | 598 | 587 | 575 | |||
Income taxes | 11 | 23 | 12 | |||
Supplemental disclosure of non-cash investing and financing activities: | ||||||
Purchase of King City Cogen Plant Lease | [5] | 0 | 0 | 15 | ||
Change in capital expenditures included in accounts payable | 13 | 19 | 20 | |||
Long-term Debt | 11,857 | 10,156 | ||||
Plant Tax Settlement Offset in Prepaid Assets | (4) | 0 | 0 | |||
Settlement of Asset Retirement Obligations Through Noncash Payments, Amount | (10) | 0 | 0 | |||
Calpine Solutions and Champion Energy [Member] | ||||||
Cash flows from investing activities: | ||||||
Purchase of Granite Ridge Energy Center | 0 | 0 | (111) | |||
King City Cogen Promissory Note [Member] | ||||||
Supplemental disclosure of non-cash investing and financing activities: | ||||||
Long-term Debt | $ 57 | |||||
Merger Related Costs [Member] | ||||||
Cash flows from financing activities: | ||||||
Payments of Dividends | $ 1 | $ 20 | ||||
[1] | Includes amortization included in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts | |||||
[2] | In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure. | |||||
[3] | Dividends paid during the years ended December 31, 2019 and 2018, includes approximately $1 million and $20 million, respectively, in certain Merger-related costs incurred by CPN Management, our parent. | |||||
[4] | Our cash and cash equivalents, restricted cash, current and restricted cash, net of current portion are stated as separate line items on our Consolidated Balance Sheets | |||||
[5] | On April 3, 2017, we completed the purchase of the King City Cogeneration Plant lease in exchange for a three-year promissory note with a discounted value of $57 million. We recorded a net increase to property, plant and equipment, net on our Consolidated Balance Sheet of $15 million due to the increased value of the promissory note as compared to the carrying value of the lease. |
Organization and Operations
Organization and Operations | 12 Months Ended |
Dec. 31, 2019 | |
Organization and Operations [Abstract] | |
Organization and Operations | Organization and Operations We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators and industrial companies, retail power providers, municipalities, CCAs and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on providing products and services that are beneficial to our wholesale and retail customers. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power and related products for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants. Merger On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub merged with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent. On March 8, 2018, we completed the Merger contemplated in the Merger Agreement. At the effective time of the Merger, each share of Calpine common stock outstanding as of immediately prior to the effective time of the Merger (excluding certain shares as described in the Merger Agreement) ceased to be outstanding and was converted into the right to receive $15.25 per share in cash or approximately $5.6 billion in total. See Note 13 for a discussion of the treatment of the outstanding share-based awards to employees at the effective time of the Merger. For the years ended December 31, 2019 , 2018 and 2017, we recorded approximately nil , $33 million and $15 million , respectively, in Merger-related costs which was recorded in other operating expenses on our Consolidated Statements of Operations and primarily related to legal, investment banking and other professional fees associated with the Merger. We elected not to apply pushdown accounting in connection with the consummation of the Merger. As a result, our assets and liabilities are recorded at historical cost and do not reflect the fair value ascribed in the Merger. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and include the accounts of all majority-owned subsidiaries that are not VIEs and all VIEs where we have determined we are the primary beneficiary. Intercompany transactions have been eliminated in consolidation. Equity Method Investments — We use the equity method of accounting to record our net interests in VIEs where we have determined that we are not the primary beneficiary, which include Greenfield LP, a 50% partnership interest and Calpine Receivables, a 100% membership interest. Our share of net income (loss) is calculated according to our equity ownership percentage or according to the terms of the applicable partnership agreement or limited liability company operating agreement. See Note 7 for further discussion of our VIEs and unconsolidated investments. Reclassifications — We have reclassified certain prior period amounts for comparative purposes. These reclassifications did not have a material effect on our financial condition, results of operations or cash flows. Jointly-Owned Plants — Certain of our subsidiaries own undivided interests in jointly-owned plants. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. We are responsible for our subsidiaries’ share of operating costs and direct expenses and include our proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of our Consolidated Financial Statements. The following table summarizes our proportionate ownership interest in jointly-owned power plants: As of December 31, 2019 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress (in millions, except percentages) Freestone Energy Center 75.0 % $ 379 $ (177 ) $ — Hidalgo Energy Center 78.5 % $ 250 $ (113 ) $ — Use of Estimates in Preparation of Financial Statements The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Financial Statements. Actual results could differ from those estimates. Fair Value of Financial Instruments and Derivatives See Note 8 for disclosures regarding the fair value of our debt instruments and Note 9 for disclosures regarding the fair values of our derivative instruments and related margin deposits and certain of our cash balances. Concentrations of Credit Risk Financial instruments that potentially subject us to credit risk consist of cash and cash equivalents, restricted cash, accounts and notes receivable and derivative financial instruments. Certain of our cash and cash equivalents, as well as our restricted cash balances, are invested in money market accounts with investment banks that are not FDIC insured. We place our cash and cash equivalents and restricted cash in what we believe to be creditworthy financial institutions and certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Additionally, we actively monitor the credit risk of our counterparties and customers, including our receivable, commodity and derivative transactions. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the U.S. We generally have not collected collateral for accounts receivable from utilities and end-user customers; however, we may require collateral in the future. For financial and commodity derivative counterparties and customers, we evaluate the net accounts receivable, accounts payable and fair value of commodity contracts and may require security deposits, cash margin or letters of credit to be posted if our exposure reaches a certain level or their credit rating declines. Our counterparties and customers primarily consist of four categories of entities who participate in the energy markets: • financial institutions and trading companies; • regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers; • oil, natural gas, chemical and other energy-related industrial companies; and • commercial, industrial and residential retail customers. We have concentrations of credit risk with a few of our wholesale counterparties and retail customers relating to our sales of power and steam and our hedging, optimization and trading activities. For example, our wholesale business currently has contracts with investor owned California utilities which could be affected should they be found liable for recent wildfires in California and, accordingly, incur substantial costs associated with the wildfires. On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. We currently have several power plants that provide energy and energy-related products to PG&E under PPAs, many of which have PG&E collateral posting requirements. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through the application of collateral. We also currently have numerous other agreements with PG&E related to the operation of our power plants in Northern California, under which PG&E has continued to provide service since its bankruptcy filing. We cannot predict the ultimate outcome of this matter and continue to monitor the bankruptcy proceedings. We have exposure to trends within the energy industry, including declines in the creditworthiness of our counterparties and customers for our commodity and derivative transactions. Currently, certain of our counterparties and customers within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty and customer credit risk and monitors our net exposure with each counterparty or customer on a daily basis. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a credit risk threshold which is determined based on each counterparties’ and customer’s credit rating and evaluation of their financial statements. We utilize these thresholds to determine the need for additional collateral or restriction of activity with the counterparty or customer. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk. Currently, our wholesale counterparties and retail customers are performing and financially settling timely according to their respective agreements with the exception of certain retail customers where our credit exposure is not material. Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. Restricted Cash Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Balance Sheets. The table below represents the components of our restricted cash as of December 31, 2019 and 2018 (in millions): 2019 2018 Current Non-Current Total Current Non-Current Total Debt service $ 58 $ 8 $ 66 $ 13 $ 8 $ 21 Construction/major maintenance 28 6 34 23 24 47 Security/project/insurance 209 31 240 120 — 120 Other 4 1 5 11 2 13 Total $ 299 $ 46 $ 345 $ 167 $ 34 $ 201 Business Interruption Proceeds We record business interruption insurance proceeds when they are realizable and recorded approximately $11 million , $14 million and $27 million of business interruption proceeds in operating revenues for the years ended December 31, 2019 , 2018 , and 2017 , respectively. Accounts Receivable and Payable Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest. Receivable balances greater than 30 days past due are reviewed for collectability, depending upon the nature of the customer, and if deemed uncollectible, are charged off against the allowance account after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best estimate to determine the required allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations. The accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging and optimization activities. Some of these receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a right of offset and settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off balance sheet credit exposure related to our customers. Inventory Inventory primarily consists of spare parts, stored natural gas and fuel oil, environmental products and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or net realizable value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to operating and maintenance expense or capitalized to property, plant and equipment as the parts are utilized and consumed. Collateral We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties and customers for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets previously subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility as collateral under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity hedge agreements” under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. The first priority liens have been granted in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. Certain of our interest rate hedging instruments relate to hedges of certain of our project financings collateralized by first priority liens on the underlying assets. See Note 11 for a further discussion on our amounts and use of collateral. Property, Plant and Equipment, Net Property, plant, and equipment items are recorded at cost. We capitalize costs incurred in connection with the construction of power plants, the development of geothermal properties and the refurbishment of major turbine generator equipment. When capital improvements to leased power plants meet our capitalization criteria, they are capitalized as leasehold improvements and amortized over the shorter of the term of the lease or the economic life of the capital improvement. We expense maintenance when the service is performed for work that does not meet our capitalization criteria. Our current capital expenditures at our Geysers Assets are those incurred for proven reserves and reservoir replenishment (primarily water injection), pipeline and power generation assets and drilling of “development wells” as all drilling activity has been performed within the known boundaries of the steam reservoir. We have capitalized costs incurred during ownership consisting of additions, certain replacements or repairs when the repairs appreciably extend the life, increase the capacity or improve the efficiency or safety of the property. Such costs are expensed when they do not meet the above criteria. We purchased our Geysers Assets as a proven steam reservoir and all well costs, except well workovers and routine repairs and maintenance, have been capitalized since our purchase date. We depreciate our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis where we own the power plant or have a favorable option to purchase the power plant or take ownership of the power plant at conclusion of the lease term and a de minimis amount of the depreciable costs basis for componentized equipment. For our Geysers Assets, we typically assume no salvage values. We use the component depreciation method for our natural gas-fired power plant rotable parts, certain componentized balance of plant parts and our information technology equipment and the composite depreciation method for the other natural gas-fired power plant asset groups and Geysers Assets. Generally, upon normal retirement of assets under the composite depreciation method, the costs of such assets are retired against accumulated depreciation and no gain or loss is recorded. For the retirement of assets under the component depreciation method, generally, the costs and related accumulated depreciation of such assets are removed from our Consolidated Balance Sheets and any gain or loss is recorded as operating and maintenance expense. Goodwill and Intangible Assets Goodwill represents the excess of the purchase price over the fair value of the net assets acquired at the time of an acquisition. We assess the carrying amount of our goodwill annually for impairment during the third quarter and whenever the events or changes in circumstances indicate that the carrying value may not be recoverable. Our goodwill resulted from the acquisition of our retail business. As such, our goodwill balance of $242 million was allocated to our Retail segment. We did not record any changes in the carrying amount of our goodwill during the years ended December 31, 2019 and 2018. We record intangible assets, such as acquired contracts, customer relationships and trademark and trade name at their estimated fair values at acquisition. We use all information available to estimate fair values including quoted market prices, if available, and other widely accepted valuation techniques. Certain estimates and judgments are required in the application of the techniques used to measure fair value of our intangible assets, including estimates of future cash flows, selling prices, replacement costs, economic lives and the selection of a discount rate, which are not observable in the market and represent a level 3 measurement. All recognized intangible assets consist of rights and obligations with finite lives. As of December 31, 2019 and 2018 , the components of our intangible assets were as follows (in millions): 2019 2018 Lives Acquired contracts $ 444 $ 458 0 – 9 Years Customer relationships 445 445 7 – 14 Years Trademark and trade name 40 40 15 Years Other 4 88 39 – 44 Years 933 1,031 Less: Accumulated amortization 593 619 Intangible assets, net $ 340 $ 412 Amortization expense related to our intangible assets for the years ended December 31, 2019 , 2018 and 2017 was $72 million , $100 million and $175 million , respectively. The estimated aggregate amortization expense of our intangible assets for the next five years is as follows (in millions): 2020 $ 44 2021 $ 39 2022 $ 36 2023 $ 28 2024 $ 28 Impairment Evaluation of Long-Lived Assets (Including Goodwill, Intangibles and Investments) We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. We test goodwill and all intangible assets not subject to amortization for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test goodwill for impairment at the reporting unit level, which is identified one level below the Company’s operating segments for which discrete financial information is available and management regularly reviews the operating results. We perform an annual impairment assessment in the third quarter of each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of a reporting unit in which goodwill resides is less than its carrying value. For reporting units in which this assessment concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and we are not required to perform the goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, overall financial performance, and other relevant events and factors affecting the reporting unit. For reporting units in which the impairment assessment concludes that it is more likely than not that the fair value is less than its carrying value, we perform the goodwill impairment test, which compares the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and we are not required to perform additional analysis. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then we record an impairment loss equal to the difference not to exceed the goodwill balance assigned to the reporting unit. We did not record an impairment of our goodwill during the years ended December 31, 2019 , 2018 and 2017 . All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value. In order to estimate future cash flows, we consider historical cash flows, existing contracts, capacity prices and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material. When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material. On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. Our power plants that sell energy and energy-related products to PG&E through PPAs, include Russell City Energy Center and Los Esteros Critical Energy Facility. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through application of collateral. As of December 31, 2019, our Consolidated Balance Sheet included net long-lived assets at Russell City Energy Center and Los Esteros Critical Energy Facility of approximately $ 647 million and $ 427 million , respectively, and non-recourse project finance debt at Russell City Energy Center and Los Esteros Critical Energy Facility of approximately $ 272 million and $ 135 million , respectively. We cannot predict whether the PPAs will be assumed through the bankruptcy proceeding, however, we believe that even if the contracts were not to be assumed, the undiscounted future cash flows of the power plants would exceed the carrying values of each of the facilities. We continue to monitor the bankruptcy proceedings for any changes in circumstances that would impact the carrying value of either power plant. We recorded impairment losses of $84 million during the year ended December 31, 2019 related to the sale of our Garrison and RockGen Energy Centers in our East segment, spare turbine equipment in our Texas segment and certain capitalized costs related to wind development projects in our Texas and East segments. We recorded impairment losses of $10 million during the year ended December 31, 2018 related to scrapped power plant equipment in our East segment. We recorded impairment losses of $41 million during the year ended December 31, 2017 related to our South Point Energy Center in our West segment and spare turbine equipment in our Texas segment. Asset Retirement Obligation We record all known asset retirement obligations for which the liability’s fair value can be reasonably estimated. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At December 31, 2019 and 2018 , our asset retirement obligation liabilities were $68 million and $63 million , respectively, primarily relating to land leases upon which our power plants are built and the requirement that the property meet specific conditions upon its return. Debt Issuance Costs Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the related debt using a method that approximates the effective interest rate method. However, when the timing of debt transactions involve contemporaneous exchanges of cash between us and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, debt issuance costs are accounted for depending on whether the transaction qualifies as an extinguishment or modification, which requires us to either write-off the original debt issuance costs and capitalize the new issuance costs, or continue to amortize the original debt issuance costs and immediately expense the new issuance costs. Our debt issuance costs related to a recognized debt liability are presented as a direct deduction from the carrying amount of the related debt liability, which is consistent with the presentation of debt discounts. Revenue Recognition Our operating revenues are comprised of the following: • power and steam revenue consisting of variable payments related to generation, retail power and gas sales activities, power revenues consisting of fixed and variable capacity payments not related to generation including capacity payments received from RTO and ISO capacity auctions, host steam, REC revenue from our Geysers Assets, other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues and realized settlements from our marketing, hedging, optimization and trading activities; • mark-to-market revenues from derivative instruments as a result of our marketing, hedging, optimization and trading activities; and • sales of natural gas and other service revenues. See Note 3 for further information related to our accounting for revenue from contracts with customers. Realized Settlements of Commodity Derivative Instruments — The realized value of power commodity sales and purchase contracts that are net settled or settled as gross sales and purchases, but could have been net settled, are reflected on a net basis and are included in Commodity revenue on our Consolidated Statements of Operations. Mark-to-Market Gain (Loss) — The changes in the mark-to-market value of power-based commodity derivative instruments are reflected on a net basis as a separate component of operating revenues. Gross vs. Net Accounting — We determine whether the financial statement presentation of revenues should be on a gross or net basis. Where we act as principal, we record settlement of our physical commodity contracts on a gross or net basis dependent upon whether the contract results in physical delivery of the underlying product. With respect to our physical executory contracts, where we do not take title to the commodities but receive a variable payment to convert natural gas into power and steam in a tolling operation, we record revenues on a net basis. Accounting for Derivative Instruments We enter into a variety of derivative instruments including both exchange traded and OTC power and natural gas forwards, options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) and interest rate hedging instruments. We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for and are designated under the normal purchase normal sale exemption. Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes may not be available from sources external to us, in which case we rely on internally developed price estimates. See Note 10 for further discussion on our accounting for derivatives. Fuel and Purchased Energy Expense Fuel and purchased energy expense is comprised of the cost of natural gas and fuel oil purchased from third parties for the purposes of consumption in our power plants as fuel, the cost of power purchased from third parties for sale to retail customers, the cost of power and natural gas purchased from third parties for our marketing, hedging and optimization activities and realized settlements and mark-to-market gains and losses resulting from general market price movements against certain derivative natural gas and power contracts including financial natural gas transactions economically hedging anticipated future power sales that either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Realized and Mark-to-Market Expenses from Commodity Derivative Instruments Realized Settlements of Commodity Derivative Instruments — The realized value of natural gas commodity purchase and sales contracts that are net settled are reflected on a net basis and included in Commodity expense on our Consolidated Statements of Operations. Power purchase commodity contracts that result in the physical delivery of power, and that also supplement our power generation, are reflected on a gross basis and are included in Commodity expense on our Consolidated Statements of Operations. Mark-to-Market (Gain) Loss — The changes in the mark-to-market value of natural gas-based and certain power-based commodity derivative instruments are reflected on a net basis as a separate component of fuel and purchased energy expense. Operating and Maintenance Expense Operating and maintenance expense primarily includes employee expenses, utilities, chemicals, repairs and maintenance (including equipment failure and major maintenance), insurance and property taxes. We recognize these expenses when the service is performed or in the period to which the expense relates. Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis and tax credit and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that includes the enactment date. We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultim |
Revenue from Contracts with Cus
Revenue from Contracts with Customers (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Revenue from Contracts with Customers [Abstract] | |
Revenue from Contract with Customer [Text Block] | Revenue from Contracts with Customers Disaggregation of Revenues with Customers The following tables represent a disaggregation of our revenue for the years ended December 31, 2019 and 2018 by reportable segment (in millions). See Note 18 for a description of our segments. Year Ended December 31, 2019 Wholesale West Texas East Retail Elimination Total Third Party: Energy & other products $ 948 $ 1,406 $ 609 $ 1,694 $ — $ 4,657 Capacity 173 125 547 — — 845 Revenues relating to physical or executory contracts – third party $ 1,121 $ 1,531 $ 1,156 $ 1,694 $ — $ 5,502 Affiliate (1) : $ 44 $ 55 $ 99 $ 9 $ (207 ) $ — Revenues relating to leases and derivative instruments (2) $ 4,570 Total operating revenues $ 10,072 Year Ended December 31, 2018 Wholesale West Texas East Retail Elimination Total Third Party: Energy & other products $ 1,070 $ 1,500 $ 621 $ 1,857 $ — $ 5,048 Capacity 152 94 657 — — 903 Revenues relating to physical or executory contracts – third party $ 1,222 $ 1,594 $ 1,278 $ 1,857 $ — $ 5,951 Affiliate (1) : $ 30 $ 34 $ 89 $ 4 $ (157 ) $ — Revenues relating to leases and derivative instruments (2) $ 3,561 Total operating revenues $ 9,512 ___________ (1) Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine. (2) Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Statements of Operations. For contracts that do not meet the requirements of a lease and either do not meet the definition of a derivative instrument or are exempt from derivative accounting, we have applied the new revenue recognition standard beginning in the first quarter of 2018. Under the new standard, the majority of our operating revenue continues to be recognized as the underlying commodity or service is delivered to our customers. Energy and Other Products Variable payments for power and steam that are based on generation, including retail sales of power, are recognized over time as the underlying commodity is generated or purchased and control is transferred to our customer upon transmission and delivery. Ancillary service revenues are also included within energy-related revenues and are recognized over time as the service is provided. For our power, steam and ancillary service contracts, we have elected the practical expedient that allows us to recognize revenue in the amount to which we have the right to invoice to the extent we determine that we have a right to consideration in an amount that corresponds directly with the value provided to date. To the extent this practical expedient cannot be utilized, we will recognize revenue over time based on the quantity of the commodity delivered to the customer for power and steam sales and over time as the service is provided for our ancillary service sales. Energy and other revenues also includes revenues generated from the sale of natural gas and environmental products, including RECs and are recognized at either a point in time or over time when control of the commodity has transferred. Revenues from the sale of RECs are primarily related to credits that are generated upon generation of renewable power from our Geysers Assets and are recognized over a period of time similar to the timing of the related energy sale. Revenues from sales of RECs or other environmental products that are not generated from our assets are recognized once all certifications have been completed and the credits are delivered to the customer at a point in time. Revenues from our natural gas sales are recognized at a point in time when delivery of the natural gas is provided. Revenues from natural gas and emission product sales are generally at the contracted transaction price, which may be fixed or index-based. Capacity Capacity revenues include fixed and variable capacity payments, which are based on generation volumes and include capacity payments received from RTO and ISO capacity auctions as well as contractual capacity under long-term PPAs. For these contracts, we have elected the practical expedient that allows us to recognize revenue in the amount to which we have the right to invoice to the extent we determine that we have a right to consideration in an amount that corresponds directly with the value provided to date. To the extent this practical expedient cannot be utilized, we will recognize revenue over time as the service is being provided to the customer. Performance Obligations and Contract Balances Certain of our contracts have multiple performance obligations. The revenues associated with each individual performance obligation is based on the relative stand-alone sales price of each good or service or, when not available, is based on a cost incurred plus margin approach. For a significant portion of our contracts with multiple performance obligations, management has applied the practical expedient that results in recognition of revenue commensurate with the invoiced amount and no allocation is required as all performance obligations are transferred over the same period of time. Certain of our contracts include volumetric optionality based on our customer’s needs. The transaction price within these contracts are based on a stand-alone sale price of the good or service being provided and revenue is recognized based on our customer’s usage. On a monthly basis, revenue is recognized based on estimated or actual usage by our customer at the transaction price. To the extent estimated usage is used in the recognition of revenue, revenues are adjusted for actual usage once known; however, this adjustment is not material to the revenues recognized. Generally, we have applied the practical expedient that allows us to recognize revenue based on the invoiced amount for these contracts. Changes in estimates for our contracts are not material and revisions to estimates are recognized when the amounts can be reasonably estimated. Unbilled retail sales are based upon estimates of customer usage since the date of the last meter reading provided by the ISOs or electric distribution companies by applying the estimated revenue per KWh by customer class to the estimated number of KWhs delivered but not yet billed. Estimated amounts are adjusted when actual usage is known and billed. During the years ended December 31, 2019 and 2018, there were no significant changes to revenue amounts recognized in prior periods as a result of a change in estimates. Sales and other taxes we collect concurrent with revenue-producing activities are excluded from our operating revenues. Billing requirements for our wholesale customers generally result in billing customers on a monthly basis in the month following the delivery of the good or service. Once billed, payment is generally required within 20 days resulting in payment for the delivery of the good or service in the month following delivery of the good or service. Billing requirements for our retail customers are generally once every 30 days and may result in billed amounts relating to our retail customers extending up to 60 days. Based on the terms of our agreements, payment is generally received at or shortly after delivery of the good or service. Changes in accounts receivable relating to our customers is primarily due to the timing difference between payment and when the good or service is provided. During the years ended December 31, 2019 and 2018, there were no significant changes in accounts receivable other than normal billing and collection transactions and there were no material credit or impairment losses recognized relating to accounts receivable balances associated with contracts with customers. When we receive consideration from a customer prior to transferring goods or services to the customer under the terms of a contract, we record deferred revenue, which represents a contract liability. Such deferred revenue typically results from consideration received prior to the transfer of goods and services relating to our capacity contracts and the sale of RECs that are not generated from our power plants. Based on the nature of these contracts and the timing between when consideration is received and delivery of the good or service is provided, these contracts do not contain any material financing elements. At December 31, 2019 and 2018 , deferred revenue balances relating to contracts with our customers were included in other current liabilities on our Consolidated Balance Sheets and primarily relate to sales of environmental products and capacity. We classify deferred revenue as current or long-term based on the timing of when we expect to recognize revenue. The balance outstanding at December 31, 2019 and 2018 , was $14 million and $14 million , respectively. The revenue recognized during the years ended December 31, 2019 and 2018 , relating to the deferred revenue balance at the beginning of the period was $14 million and $15 million and resulted from our performance under the customer contracts. The change in the deferred revenue balance during the years ended December 31, 2019 and 2018 was primarily due to the timing difference of when consideration was received and when the related good or service was transferred. Contract Costs For certain retail contracts, we incur third party incremental broker costs that are capitalized on our Consolidated Balance Sheets. Capitalized contract costs are amortized on a straight line basis over the term of the underlying sales contract to the extent the term extends beyond one year. Contract costs associated with sales contracts that are less than one year are expensed as incurred under a practical expedient. At December 31, 2019 and 2018 , the capitalized contract cost balance was not material. There were no impairment losses or changes in amortization during the years ended December 31, 2019 and 2018 and amortization of contract costs during the years ended December 31, 2019 and 2018 was immaterial. Performance Obligations not yet Satisfied As of December 31, 2019 , we have entered into certain contracts for fixed and determinable amounts with customers under which we have not yet completed our performance obligations which primarily includes agreements for which we are providing capacity from our generating facilities. We have revenues related to the sale of capacity through participation in various ISO capacity auctions estimated based upon cleared volumes and the sale of capacity to our customers of $639 million , $633 million , $408 million , $141 million and $49 million that will be recognized during the years ending December 31, 2020, 2021, 2022, 2023 and 2024, respectively, and $63 million thereafter. Revenues under these contracts will be recognized as we transfer control of the commodities to our customers. |
Leases (Notes)
Leases (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Lessee and Lessor Leases [Text Block] | Leases Accounting for Leases – Lessee We evaluate contracts for lease accounting at contract inception and assess lease classification at the lease commencement date. For our leases, we recognize a right-of-use asset and corresponding lease obligation liability at the lease commencement date where the lease obligation liability is measured at the present value of the minimum lease payments. For our operating leases, the amortization of the right-of-use asset and the accretion of our lease obligation liability result in a single straight-line expense recognized over the lease term. We determine the discount rate associated with our operating and finance leases using our incremental borrowing rate at lease commencement. For our operating leases, we use an interest rate commensurate with the interest rate to borrow on a collateralized basis over a similar term with an amount equal to the lease payments. Factors management considers in the calculation of the discount rate include the amount of the borrowing, the lease term including options that are reasonably certain of exercise, the current interest rate environment and the credit rating of the entity. For our finance leases, we use the interest rate commensurate with the interest rate for a project finance borrowing arrangement with a similar collateral package, repayment terms, restrictive covenants and guarantees. Our operating leases are primarily related to office space for our corporate and regional offices as well as land and operating related leases for our power plants. Additionally, one of our power plants is accounted for as an operating lease. Payments made by Calpine on this lease are recognized on a straight-line basis with capital improvements associated with our leased power plant deemed leasehold improvements that are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Several of our leases contain renewal options held by us to extend the lease term. The inclusion of these renewal periods in the lease term and in the minimum lease payments included in our lease liabilities is dependent on specific facts and circumstances for each lease and whether it is determined to be reasonably certain that we will exercise our option to extend the term. Our office, land and other operating leases do not contain any material restrictive covenants or residual value guarantees. We have entered into finance leases for certain power plants and related equipment with terms that range up to 30 years (including lease renewal options). The finance leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. In connection with our adoption of Topic 842 on January 1, 2019, we elected certain practical expedients that were available under the new lease standards including: • we elected not to separate lease and non-lease components for our current classes of underlying leased assets as the lessee; • we did not evaluate existing and expired land easements that were not previously accounted for as leases prior to January 1, 2019; and • we did not reassess the classification of leases, the accounting for initial direct costs or whether contractual arrangements contained a lease for all contracts that expired or commenced prior to January 1, 2019. Further, upon the adoption of Topic 842, we made an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. We do not have any material subleases associated with our operating and finance leases. The components of our operating and finance lease expense are as follows for the year ended December 31, 2019 (in millions): December 31, 2019 Operating Leases Operating lease expense $ 46 Finance Leases Amortization of the right-of-use assets 8 Interest expense 8 Finance lease expense $ 16 Variable lease expense 9 Total lease expense $ 71 The following is a schedule by year of future minimum lease payments associated with our operating and finance leases together with the present value of the net minimum lease payments as of December 31, 2019 (in millions): Operating Leases (1) Finance Leases (2) 2020 $ 21 $ 16 2021 22 16 2022 20 15 2023 19 19 2024 18 8 Thereafter 185 26 Total minimum lease payments 285 100 Less: Amount representing interest 103 27 Total lease obligation 182 73 Less: current lease obligation 12 10 Long-term lease obligation $ 170 $ 63 ____________ (1) The lease liabilities associated with our operating leases as of December 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Balance Sheet. (2) The lease liabilities associated with our finance leases as of December 31, 2019 are included in debt, current portion and debt, net of current portion on our Consolidated Balance Sheet. Supplemental balance sheet information related to our operating and finance leases is as follows as of December 31, 2019 (in millions, except lease term and discount rate): December 31, 2019 Operating leases (1) Right-of-use assets associated with operating leases $ 171 Finance leases (2) Property, plant and equipment, gross 212 Accumulated amortization (105 ) Property, plant and equipment, net $ 107 Weighted average remaining lease term (in years) Operating leases 17.5 Finance leases 6.8 Weighted average discount rate Operating leases 5.1 % Finance leases 8.0 % ____________ (1) The right-of-use assets associated with our operating leases as of December 31, 2019 are included in other assets on our Consolidated Balance Sheet. (2) The right-of-use assets associated with our finance leases as of December 31, 2019 are included in property, plant and equipment, net on our Consolidated Balance Sheet. Supplemental cash flow information related to our operating and finance leases is as follows for the period presented (in millions): December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 54 Operating cash flows from finance leases $ 8 Financing cash flows from finance leases $ 11 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 14 Finance leases $ — Accounting for Leases – Lessor We apply lease accounting to PPAs that meet the definition of a lease and determine lease classification treatment at commencement of the agreement. We currently do not have any contracts which are accounted for as sales-type leases or direct financing leases and all of our leases as the lessor are classified as operating leases. As part of the implementation of Topic 842, we elected the practical expedient to not reassess leases that have commenced prior to January 1, 2019. Revenue from contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals (capacity payments) which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract. Our operating leases that have commenced contain terms extending through May 2042. These contracts also generally contain variable payment components based on generation volumes or operating efficiency over a period of time. Revenues associated with the variable payments are recognized over time as the goods or services are provided to the lessee. Our operating leases generally do not contain renewal or purchase options or residual value guarantees. We have elected to not separate our lease and non-lease components as the lease components reflect the predominant characteristics of these agreements. Revenue recognized related to fixed lease payments on our operating leases for the period presented is as follows (in millions): 2019 Operating Leases (1) Fixed lease payments $ 341 ____________ (1) Revenues associated with our operating leases are included in Commodity revenue and other revenue on our Consolidated Statement of Operations. The total contractual future minimum lease rentals for our contracts that have commenced and are accounted for as operating leases at December 31, 2019 , are as follows (in millions): 2020 $ 286 2021 261 2022 226 2023 144 2024 50 Thereafter 236 Total $ 1,203 We do not recognize lease receivables associated with our operating leases as the long-lived assets subject to the lease contracts are recorded on our Consolidated Balance Sheet and are being depreciated over their estimated useful lives. Amounts recorded on our Consolidated Balance Sheet associated with the long-lived assets subject to our operating leases as of December 31, 2019 are as follows (in millions): December 31, 2019 Assets subject to contracts accounted for as operating leases Property, plant and equipment, gross $ 2,561 Accumulated depreciation (770 ) Property, plant and equipment, net (1) $ 1,791 ____________ (1) Our assets subject to contracts that are accounted for as operating leases primarily consist of our power plants subject to tolling contracts. We also record lease levelization assets and liabilities for any difference between the timing of the contractual payments made related to our operating lease contracts and revenue recognized on a straight-line basis. These balances are included in current and long-term assets and liabilities on our Consolidated Balance Sheet. Disclosures for periods prior to the adoption of Topic 842 Lessee The following is a schedule by year of future minimum lease payments under operating and capital leases as of December 31, 2018 (in millions): Operating Leases (1) Capital Leases (2) 2019 $ 50 $ 40 2020 19 40 2021 20 38 2022 18 33 2023 17 27 Thereafter 192 92 Total minimum lease payments $ 316 270 Less: Amount representing interest 89 Present value of net minimum lease payments $ 181 ____________ (1) During the years ended December 31, 2018 and 2017, expense for operating leases amounted to $53 million and $50 million , respectively. (2) Includes a failed sale-leaseback transaction related to our Pasadena Power Plant. At December 31, 2018, the asset balance for our assets under capital leases totaled approximately $715 million with accumulated amortization of $353 million . Amortization of assets under capital leases is recorded in depreciation and amortization expense on our Consolidated Statements of Operations. Lessor The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2018, are as follows (in millions): 2019 $ 342 2020 261 2021 257 2022 224 2023 141 Thereafter 239 Total $ 1,464 |
Acquisitions, Divestitures and
Acquisitions, Divestitures and Discontinued Operations Acquisitions and Divestitures (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Mergers, Acquisitions and Dispositions Disclosures [Text Block] | Acquisitions and Divestitures Acquisition of North American Power On January 17, 2017, we, through an indirect, wholly-owned subsidiary, completed the purchase of 100% of the outstanding limited liability company membership interests in North American Power for approximately $105 million , excluding working capital and other adjustments. North American Power is a retail energy supplier for homes and small businesses and is primarily concentrated in the Northeast U.S. where Calpine has a substantial power generation presence and where Champion Energy has a substantial retail sales footprint that is enhanced by the addition of North American Power, which has been integrated into our Champion Energy retail platform. We funded the acquisition with cash on hand and the purchase price is allocated to the net assets of the business including intangible assets for the value of customer relationships and goodwill. The goodwill recorded associated with our acquisition of North American Power is deductible for tax purposes. The purchase price allocation was finalized during the fourth quarter of 2017 which did not result in any material adjustments. The pro forma incremental effect of North American Power on our results of operations for the year ended December 31, 2017 is not material. Sale of Garrison Energy Center and RockGen Energy Center On July 10, 2019, we, through our indirect, wholly owned subsidiaries Calpine Holdings, LLC and Calpine Northbrook Project Holdings, LLC, completed the sale of 100% of our ownership interests in Garrison Energy Center LLC (“Garrison”) and RockGen Energy LLC (“RockGen”) to Cobalt Power, L.L.C. for approximately $360 million , subject to certain immaterial working capital adjustments and the execution of financial commodity contracts. Upon closing, we recognized a liability of $52 million for the fair value of the financial commodity contracts on our Consolidated Balance Sheet, and the related proceeds are reflected within the financing section on our Consolidated Statement of Cash Flows. Garrison owns the Garrison Energy Center, a 309 MW natural gas-fired, combined-cycle power plant located in Dover, Delaware, and RockGen owns the RockGen Energy Center, a 503 MW natural gas-fired, simple-cycle power plant located in Christiana, Wisconsin. We used the sale proceeds, together with cash on hand, to fund a dividend of $400 million to our parent, CPN Management. We recorded an immaterial gain on the sale during the third quarter of 2019 and an impairment loss of $55 million for the year ended December 31, 2019, to adjust the carrying value of the assets to reflect fair value less cost to sell. Sale of Osprey Energy Center On January 3, 2017, we completed the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million , excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. We recorded a gain on sale of assets, net of approximately $27 million during the year ended December 31, 2017 associated with the sale of the Osprey Energy Center. |
Property, Plant and Equipment,
Property, Plant and Equipment, Net | 12 Months Ended |
Dec. 31, 2019 | |
Property, Plant and Equipment, Net [Abstract] | |
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net As of December 31, 2019 and 2018 , the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions): 2019 2018 Depreciable Lives Buildings, machinery and equipment $ 16,510 $ 16,400 1.5 – 50 Years Geothermal properties 1,553 1,501 13 – 58 Years Other 291 286 3 – 50 Years 18,354 18,187 Less: Accumulated depreciation 6,851 6,832 11,503 11,355 Land 128 121 Construction in progress 332 966 Property, plant and equipment, net $ 11,963 $ 12,442 Total depreciation expense, including amortization of finance lease assets, recorded for the years ended December 31, 2019 , 2018 and 2017 , was $627 million , $684 million and $638 million , respectively. We have various debt instruments that are collateralized by our property, plant and equipment. See Note 8 for a discussion of such instruments. Buildings, Machinery and Equipment This component primarily includes power plants and related equipment. Included in buildings, machinery and equipment are assets under finance leases. See Note 4 for further information regarding these assets under finance leases. Geothermal Properties This component primarily includes power plants and related equipment associated with our Geysers Assets. Other This component primarily includes software and hardware as well as emission reduction credits that are power plant specific and not available to be sold. Capitalized Interest The total amount of interest capitalized was $12 million , $29 million and $26 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. |
Variable Interest Entities and
Variable Interest Entities and Unconsolidated Investments | 12 Months Ended |
Dec. 31, 2019 | |
Variable Interest Entities and Unconsolidated Investments [Abstract] | |
Variable Interest Entities and Unconsolidated Investments [Text Block] | Variable Interest Entities and Unconsolidated Investments We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the year ended December 31, 2019 . We have the following types of VIEs consolidated in our financial statements: Subsidiaries with Project Debt — All of our subsidiaries with project debt not guaranteed by Calpine have PPAs that provide financial support and are thus considered VIEs. We retain ownership and absorb the full risk of loss and potential for reward once the project debt is paid in full. Actions by the lender to assume control of collateral can occur only under limited circumstances such as upon the occurrence of an event of default. See Note 8 for further information regarding our project debt and Note 2 for information regarding our restricted cash balances. Subsidiaries with PPAs — Certain of our majority owned subsidiaries have PPAs that limit the risk and reward of our ownership and thus constitute a VIE. VIE with a Purchase Option — OMEC had a ten-year tolling agreement with SDG&E which commenced on October 3, 2009 and expired on October 2, 2019. Under a ground lease agreement, OMEC held a put option to sell the Otay Mesa Energy Center for $280 million to SDG&E, pursuant to the terms and conditions of the agreement, which was exercisable until April 1, 2019 and SDG&E held a call option to purchase the Otay Mesa Energy Center for $377 million , which was exercisable through October 3, 2018. The call option held by SDG&E expired unexercised. OMEC has executed a new 59-month Resource Adequacy (“RA”) contract with SDG&E. The RA contract received initial regulatory approval by the CPUC on February 21, 2019. This approval was subject to a 30 day appeal period from the date of the issuance of the CPUC decision. On March 27, 2019, an appeal of the CPUC decision was filed with the CPUC. Accordingly, on March 28, 2019, we provided notice of our exercise of the put option, which we subsequently rescinded by agreement following the CPUC’s denial of all appeals of the new RA contract on August 1, 2019. On October 3, 2019, the RA contract with SDG&E commenced. As a result, we retained the 608 MW Otay Mesa Energy Center, which plays an integral role in electric reliability in Southern California. As the call and put options have terminated and the project debt has been fully repaid, we determined that OMEC no longer meets the definition of a VIE during the third quarter of 2019. Consolidation of VIEs We consolidate our VIEs where we determine that we have both the power to direct the activities of a VIE that most significantly affect the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE. We have determined that we hold the obligation to absorb losses and receive benefits in almost all of our VIEs where we hold the majority equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following primary activities which we believe to have a significant effect on a power plant’s financial performance: operations and maintenance, plant dispatch, and fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities for most of our majority-owned VIEs. Under our consolidation policy and under U.S. GAAP we also: • perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and • evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur, such as contractual changes where the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly affect the VIE’s economic performance or when there are other changes in the powers held by individual variable interest holders. Noncontrolling Interest — At December 31, 2019 , we owned a 75% interest in Russell City Energy Company, LLC, one of our VIEs, which was also 25% owned by a third party. On January 28, 2020, we completed the acquisition of the 25% noncontrolling interest of Russell City Energy Company, LLC for approximately $49 million . For the year ended December 31, 2019, we fully consolidated this entity in our Consolidated Financial Statements and accounted for the third party ownership interest as a noncontrolling interest. VIE Disclosures Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 6,669 MW and 7,880 MW, at December 31, 2019 and 2018 , respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. On August 14, 2019, we repaid the OMEC project debt outstanding balance utilizing a portion of the proceeds from our 2026 First Lien Term Loans and cash on hand. See above for further discussion of OMEC. Other than amounts contractually required, we provided no additional material support to our VIEs in the form of cash and other contributions during each of the years ended December 31, 2019 , 2018 and 2017 . U.S. GAAP requires separate disclosure on the face of our Consolidated Balance Sheets of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In determining which assets of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where Calpine Corporation is substantially limited or prohibited from access to assets (including cash and cash equivalents, restricted cash and property, plant and equipment), and where our VIEs have project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation. Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries We have a 50% partnership interest in Greenfield LP which is also a VIE; however, we do not have the power to direct the most significant activities of this entity and therefore do not consolidate it. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. On November 20, 2019, we sold our 50% interest in Whitby, a limited partnership, which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. Calpine Receivables is a VIE and a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. We have determined that we do not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, we have determined that we are not the primary beneficiary of Calpine Receivables because we do not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls management of default. Thus, we do not consolidate Calpine Receivables in our Consolidated Financial Statements and use the equity method of accounting to record our net interest in Calpine Receivables. We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Balance Sheets. At December 31, 2019 and 2018 , our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions): Ownership Interest as of December 31, 2019 2019 2018 Greenfield LP (1) 50% $ 66 $ 55 Whitby (2) —% — 15 Calpine Receivables 100% 4 6 Total investments in unconsolidated subsidiaries $ 70 $ 76 ____________ (1) Includes our share of accumulated other comprehensive income/loss related to interest rate hedging instruments associated with our unconsolidated subsidiary Greenfield LP’s debt. (2) On November 20, 2019, we sold our 50% interest in Whitby to a third party and recorded a gain on sale of assets, net of approximately $5 million . Our risk of loss related to our investment in Greenfield LP is limited to our investment balance. Our risk of loss related to our investment in Calpine Receivables is $48 million which consists of our notes receivable from Calpine Receivables at December 31, 2019 , and our initial investment associated with Calpine Receivables. See Note 17 for further information associated with our related party activity with Calpine Receivables. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Balance Sheets. At December 31, 2019 and 2018 , Greenfield LP’s debt was approximately $299 million and $ 301 million , respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $150 million and $ 151 million at December 31, 2019 and 2018 , respectively. Our equity interest in the net income from our investments in unconsolidated subsidiaries for the years ended December 31, 2019 , 2018 and 2017 , is recorded in (income) loss from unconsolidated subsidiaries. The following table sets forth details of our (income) loss from unconsolidated subsidiaries and distributions for the years indicated (in millions): (Income) loss from Unconsolidated Subsidiaries Distributions 2019 2018 2017 2019 2018 2017 Greenfield LP $ (13 ) $ (11 ) $ (14 ) $ — $ 48 $ 8 Whitby (1) (11 ) (15 ) (10 ) 26 5 20 Calpine Receivables 2 2 2 — — — Total $ (22 ) $ (24 ) $ (22 ) $ 26 $ 53 $ 28 ____________ (1) On November 20, 2019, we sold our 50% interest in Whitby to a third party. Inland Empire Energy Center Put and Call Options — We held a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) at predetermined prices from GE that could be exercised between years 2017 and 2024 . GE held a put option whereby they could require us to purchase the power plant, if certain plant performance criteria were met by 2025 . On February 1, 2019, we entered into an agreement with GE, which among other things, terminated our call option and GE’s put option related to the Inland Empire Energy Center. As per this agreement, we will take ownership of the facility site and certain remaining site infrastructure and equipment after closure and decommissioning of the facility at a future date, until such time GE continues to own, operate and maintain the power plant, including directing any closure activities. As GE continues to direct all such significant activities of the power plant, we have determined that we no longer hold any variable interests in the Inland Empire Energy Center and it is not a VIE to Calpine. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Debt | Debt Our debt at December 31, 2019 and 2018 , was as follows (in millions): 2019 2018 Senior Unsecured Notes $ 3,663 $ 3,036 First Lien Term Loans 3,167 2,976 First Lien Notes 2,835 2,400 Project financing, notes payable and other 879 1,264 CCFC Term Loan 967 974 Finance lease obligations 73 105 Revolving facilities 122 30 Subtotal 11,706 10,785 Less: Current maturities 1,268 637 Total long-term debt $ 10,438 $ 10,148 Our debt agreements contain covenants which could permit lenders to accelerate the repayment of our debt by providing notice, the lapse of time, or both, if certain events of default remain uncured after any applicable grace period. We were in compliance with all of the covenants in our debt agreements at December 31, 2019 . Our effective interest rate on our consolidated debt, excluding the effects of capitalized interest and mark-to-market gains (losses) on interest rate hedging instruments, increased to 5.8% for the year ended December 31, 2019 from 5.7% for the year ended December 31, 2018 . Annual Debt Maturities Contractual annual principal repayments or maturities of debt instruments as of December 31, 2019 , are as follows (in millions): 2020 $ 1,269 2021 347 2022 230 2023 198 2024 2,030 Thereafter 7,771 Subtotal 11,845 Less: Debt issuance costs 114 Less: Discount 25 Total debt $ 11,706 Senior Unsecured Notes Our Senior Unsecured Notes are summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average (1) 2019 2018 2019 2018 2023 Senior Unsecured Notes (2) $ 623 $ 1,227 5.7 % 5.6 % 2024 Senior Unsecured Notes 479 599 5.7 5.7 2025 Senior Unsecured Notes 1,174 1,210 5.8 6.0 2028 Senior Unsecured Notes (2) 1,387 — 5.3 — Total Senior Unsecured Notes $ 3,663 $ 3,036 ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs. (2) On December 27, 2019, we used the proceeds from the issuance of our 2028 Senior Unsecured Notes (discussed below) to redeem approximately $613 million in aggregate principal amount of our 2023 Senior Unsecured Notes, plus accrued and unpaid interest. On January 21, 2020, we redeemed the remaining $623 million in aggregate principal amount of our 2023 Senior Unsecured Notes, which was included in debt, current portion on our Consolidated Balance Sheet at December 31, 2019, with the proceeds from the 2028 Senior Unsecured Notes, which was included in cash and cash equivalents on our Consolidated Balance Sheet at December 31, 2019 . We recorded approximately $24 million in loss on extinguishment of debt which is comprised of approximately $18 million of prepayment premiums and approximately $6 million associated with the write-off of unamortized debt issuance costs during the fourth quarter of 2019 associated with the redemption. During the year ended December 31, 2019 , we repurchased $160 million in aggregate principal amount of our Senior Unsecured Notes for $158 million . In connection with the repurchases, we recorded approximately $2 million in gain on extinguishment of debt and recorded an immaterial amount in loss on extinguishment of debt associated with the write-off of debt issuance costs. During the year ended December 31, 2018, we repurchased $390 million in aggregate principal of our Senior Unsecured Notes for $355 million . In connection with the repurchases, we recorded approximately $35 million in gain on extinguishment of debt and recorded approximately $3 million in loss on extinguishment of debt associated with the write-off of debt issuance costs. Year Ended December 31, 2019 Year Ended December 31, 2018 Principal Repurchased Cash Paid Gain (loss) on Extinguishment of Debt Principal Repurchased Cash Paid Gain on Extinguishment of Debt (in million) 2023 Senior Unsecured Notes $ — $ — $ — $ 14 $ 13 $ 1 2024 Senior Unsecured Notes 122 123 (1 ) 46 42 4 2025 Senior Unsecured Notes 38 35 3 330 300 30 Total $ 160 $ 158 $ 2 $ 390 $ 355 $ 35 On December 27, 2019, we issued $ 1.4 billion in aggregate principal amount of 5.125% senior unsecured notes due 2028 in a private placement. The 2028 Senior Unsecured Notes bear interest at 5.125% per annum with interest payable semi-annually on March 15 and September 15 of each year, beginning on September 15, 2020. The 2028 Senior Unsecured Notes mature on March 15, 2028. We recorded approximately $13 million in debt issuance costs during the fourth quarter of 2019 in connection with the issuance of our 2028 Senior Unsecured Notes. In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024 in a public offering. The 2024 Senior Unsecured Notes bear interest at 5.5% per annum with interest payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2015. The 2024 Senior Unsecured Notes were issued at par, mature on February 1, 2024 and contain substantially similar covenant, qualifications, exceptions and limitations as our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes. On July 22, 2014, we issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering. The 2023 Senior Unsecured Notes bear interest at 5.375% per annum and the 2025 Senior Unsecured Notes bear interest at 5.75% per annum, in each case payable semi-annually on April 15 and October 15 of each year, beginning on April 15, 2015. The 2023 Senior Unsecured Notes mature on January 15, 2023 and the 2025 Senior Unsecured Notes mature on January 15, 2025. Our Senior Unsecured Notes were issued at par. Our Senior Unsecured Notes are: • general unsecured obligations of Calpine; • rank equally in right of payment with all of Calpine’s existing and future senior indebtedness; • effectively subordinated to Calpine’s secured indebtedness to the extent of the value of the collateral securing such indebtedness; • structurally subordinated to any existing and future indebtedness and other liabilities of Calpine’s subsidiaries; and • senior in right of payment to any of Calpine’s subordinated indebtedness. First Lien Term Loans Our First Lien Term Loans are summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates (1) 2019 2018 2019 2018 2019 First Lien Term Loan $ — $ 389 — % 4.9 % 2023 First Lien Term Loans — 1,059 — 5.4 2024 First Lien Term Loan (2) 1,514 1,528 5.3 5.0 2026 First Lien Term Loans 1,653 — 5.4 — Total First Lien Term Loans $ 3,167 $ 2,976 ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. (2) Our 2024 First Lien Term Loan, which matures on January 15, 2024, carries substantially similar terms as our $950 million first lien senior secured term loan as discussed below. On August 12, 2019, we entered into a $ 750 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the credit agreement), plus an applicable margin of 1.0% , or (ii) LIBOR plus 2.00% per annum, which reflects the lower rate resulting from the repricing on February 12, 2020, (with a 0% LIBOR floor) and matures on August 12, 2026. An aggregate amount equal to 0.25% of the aggregate principal amount is payable at the end of each quarter with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 0.50% of the aggregate principal amount, which is structured as original issue discount and recorded approximately $ 11 million in debt issuance costs during the third quarter of 2019 related to the issuance of our $ 750 million first lien senior secured term loan. The $ 750 million first lien senior secured term contains substantially similar covenants, qualifications, exceptions and limitations as our First Lien Term Loans and First Lien Notes. We used the proceeds, together with cash on hand, to repay the remaining 2023 First Lien Term Loans with a maturity date in May 2023 and to repay project debt associated with OMEC. We recorded approximately $ 12 million in loss on extinguishment of debt during the third quarter of 2019 associated with the repayment. On April 5, 2019, we entered into a $ 950 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the credit agreement), plus an applicable margin of 1.25% , or (ii) LIBOR plus 2.25% per annum, which reflects the lower rate resulting from the repricing on December 20, 2019, (with a 0% LIBOR floor) and matures on April 5, 2026. An aggregate amount equal to 0.25% of the aggregate principal amount is payable at the end of each quarter with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount, which is structured as original issue discount and recorded approximately $ 7 million in debt issuance costs during the second quarter of 2019 related to the issuance of our $ 950 million first lien senior secured term loan. The $ 950 million first lien senior secured term loan contains substantially similar covenants, qualifications, exceptions and limitations as our First Lien Term Loans and First Lien Notes. We used the proceeds to repay our 2019 First Lien Term Loan and a portion of our 2023 First Lien Term Loans with a maturity date in January 2023 and recorded approximately $ 3 million in loss on extinguishment of debt during the second quarter of 2019 associated with the repayment. First Lien Notes Our First Lien Notes are summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average (1) 2019 2018 2019 2018 2022 First Lien Notes (2) $ 245 $ 743 6.4 % 6.4 % 2024 First Lien Notes (3) 184 486 6.1 6.1 2026 First Lien Notes 1,172 1,171 5.5 5.5 2028 First Lien Notes (2)(3) 1,234 — 4.7 — Total First Lien Notes $ 2,835 $ 2,400 ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. (2) On December 20, 2019, we used the proceeds from the issuance of our 2028 First Lien Notes (discussed below) to redeem approximately $505 million in aggregate principal amount of our 2022 First Lien Notes, plus accrued and unpaid interest. On January 21, 2020, we redeemed the remaining $245 million in aggregate principal amount of our 2022 First Lien Notes, which was included in debt, current portion on our Consolidated Balance Sheet at December 31, 2019, with the proceeds from the 2028 First Lien Notes, which was included in cash and cash equivalents on our Consolidated Balance Sheet at December 31, 2019 . We recorded approximately $6 million in loss on extinguishment of debt which is comprised of approximately $1 million of prepayment premiums and approximately $5 million associated with the write-off of unamortized discount and debt issuance costs during the fourth quarter of 2019 associated with the redemption. (3) On December 20, 2019, we used the proceeds from the issuance of our 2028 First Lien Notes (discussed below) to redeem approximately $306 million of the total aggregate debt amount of 2024 First Lien Notes, plus accrued and unpaid interest. On January 21, 2020, we redeemed the remaining $184 million in aggregate principal amount of our 2024 First Lien Notes, which was included in debt, current portion on our Consolidated Balance Sheet at December 31, 2019, with the proceeds from the 2028 First Lien Notes which was included in cash and cash equivalents on our Consolidated Balance Sheet at December 31, 2019 . We recorded approximately $14 million in loss on extinguishment of debt which is comprised of approximately $11 million of prepayment premiums and approximately $3 million associated with the write-off of unamortized debt issuance costs during the fourth quarter of 2019 associated with the redemption. On December 20, 2019, we issued $1.25 billion in aggregate principal amount of 4.50% senior secured notes due 2028 in a private placement. Our 2028 First Lien Notes bear interest at 4.50% payable semi-annually on February 15 and August 15 of each year, beginning on August 15, 2020. Our 2028 First Lien Notes mature on February 15, 2028 and contain substantially similar covenants, qualifications, exceptions and limitations as our First Lien Notes. We recorded approximately $16 million in debt issuance costs during the fourth quarter of 2019 related to the issuance of our 2028 First Lien Notes. On December 15, 2017, we issued $560 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. Additionally, on May 31, 2016, we issued $625 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. Our 2026 First Lien Notes bear interest at 5.25% payable semi-annually on June 1 and December 1 of each year. Our 2026 First Lien Notes mature on June 1, 2026 and contain substantially similar covenants, qualifications, exceptions and limitations as our First Lien Notes. We recorded approximately $8 million in debt issuance costs during the fourth quarter of 2017 related to the issuance of a portion of our 2026 First Lien Notes and approximately $9 million in debt issuance costs during the second quarter of 2016 related to the issuance of a portion of our 2026 First Lien Notes. Our First Lien Notes are secured equally and ratably with indebtedness incurred under our First Lien Term Loans and Corporate Revolving Facility, subject to certain exceptions and permitted liens, on substantially all of our and certain of the guarantors’ existing and future assets. Additionally, our First Lien Notes rank equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee our First Lien Notes. Subject to certain qualifications and exceptions, our First Lien Notes will, among other things, limit our ability and the ability of the guarantors to: • incur or guarantee additional first lien indebtedness; • enter into certain types of commodity hedge agreements that can be secured by first lien collateral; • enter into sale and leaseback transactions; • create or incur liens; and • consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries on a combined basis. Project Financing, Notes Payable and Other The components of our project financing, notes payable and other are (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates (1) 2019 2018 2019 2018 Russell City due 2023 $ 272 $ 341 6.6 % 6.5 % Steamboat due 2025 351 384 4.6 4.5 OMEC due 2024 (2) — 218 — 7.1 Los Esteros due 2023 135 163 5.2 4.7 Pasadena (3) 62 76 8.9 8.9 Bethpage Energy Center 3 due 2020-2025 (4) 45 53 7.0 7.1 Other 14 29 — — Total $ 879 $ 1,264 _____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. (2) On August 14, 2019, we repaid the project debt associated with OMEC from a portion of the proceeds received from the issuance of our 2026 First Lien Term Loans (as discussed above), together with cash on hand. (3) Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP. (4) Represents a weighted average of first and second lien loans for the weighted average effective interest rates. Our project financings are collateralized solely by the capital stock or partnership interests, physical assets, contracts and/or cash flows attributable to the entities that own the power plants. The lenders’ recourse under these project financings is limited to such collateral. On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. Our power plants that sell energy and energy-related products to PG&E through PPAs, include Russell City Energy Center and Los Esteros Critical Energy Facility. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through application of collateral. As a result of PG&E’s bankruptcy, we are currently unable to make distributions from our Russell City and Los Esteros projects in accordance with the terms of the project debt agreements associated with each related project. In July 2019, we executed forbearance agreements associated with the Russell City and Los Esteros project debt agreements, under which the lenders have agreed to forbear enforcement of their rights and remedies, including the ability to accelerate the repayment of borrowings outstanding, otherwise arising because PG&E did not assume our PPAs during the first 180 days of PG&E’s bankruptcy proceeding. The forbearance agreements are effective for rolling 90-day periods, so long as we continue to meet certain conditions, including that the PPAs have not been rejected and there are no other defaults under the project debt agreements or the forbearance agreements. We may be required to reclassify $304 million of Russell City and Los Esteros long-term project debt outstanding at December 31, 2019 to a current liability in a future period. We continue to monitor the bankruptcy proceedings and are assessing our options. CCFC Term Loan Our CCFC Term Loan is summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates (1) 2019 2018 2019 2018 CCFC Term Loan $ 967 $ 974 5.2 % 4.9 % ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. On December 15, 2017, CCFC entered into a credit agreement providing for a first lien senior secured term loan facility for $1.0 billion . The CCFC Term Loan bears interest, at CCFC’s option, at either (i) the Base Rate, equal to the higher of (a) the Federal Funds Effective Rate plus 0.5% per annum, (b) the Prime Rate or (c) the Eurodollar Rate (as such terms are defined in the Credit Agreement) plus 1.0% per annum, plus an applicable margin of 1.0% per annum, or (ii) LIBOR plus 2.0% per annum, which reflects the lower rate resulting from the repricing on January 29, 2020. The CCFC Term Loan was offered to investors at an issue price equal to 99.875% of face value. An aggregate amount equal to 0.25% of the aggregate principal amount of the CCFC Term Loan will be payable at the end of each quarter commencing in March 2018, with the remaining balance payable on the maturity date (January 15, 2025). CCFC may elect from time to time to convert all or a portion of the CCFC Term Loan from LIBOR rate loans to Base Rate loans or vice versa. In addition, CCFC may at any time, and from time to time, prepay the CCFC Term Loan, in whole or in part, without premium or penalty, upon irrevocable notice to the Administrative Agent. Partial prepayments shall be in an aggregate minimum principal amount of $1 million , provided that any prepayment shall be first applied to any portion of the CCFC Term Loan that is designated as Base Rate loans and then LIBOR rate loans. CCFC may also reprice the CCFC Term Loan, subject to approval from the Lenders (as defined in the Credit Agreement). CCFC may elect to extend the maturity of any CCFC Term Loan, in whole or in part, subject to approval from those lenders (as defined in the Credit Agreement) holding such CCFC Term Loan. Subject to certain qualifications and exceptions, the Credit Agreement will, among other things, limit CCFC’s ability and the ability of the guarantors of the CCFC Term Loan to: • incur or guarantee additional first lien indebtedness; • enter into sale and leaseback transactions; • create liens; • consummate certain asset sales; • make certain non-cash restricted payments; and • consolidate, merge or transfer all or substantially all of CCFC’s assets and the assets of CCFC’s restricted subsidiaries on a combined basis. We utilized the proceeds received from a portion of our 2026 First Lien Notes (discussed above) and the CCFC Term Loan, together with operating cash on hand, to fully repay the CCFC Term Loans and recorded approximately $13 million in debt issuance costs during the fourth quarter of 2017. We recorded approximately $12 million in loss on extinguishment of debt associated with the repayment of our CCFC Term Loans during the fourth quarter of 2017. The CCFC Term Loan is secured by certain real and personal property of CCFC consisting primarily of six natural gas-fired power plants. The CCFC Term Loan is not guaranteed by Calpine Corporation and is without recourse to Calpine Corporation or any of our non-CCFC subsidiaries or assets; however, CCFC generates the majority of its cash flows from an intercompany tolling agreement with Calpine Energy Services, L.P. and has various service agreements in place with other subsidiaries of Calpine Corporation. Finance Lease Obligations See Note 4 for disclosures related to our finance lease obligations. Corporate Revolving Facility and Other Letters of Credit Facilities The table below represents amounts issued under our letter of credit facilities at December 31, 2019 and 2018 (in millions): 2019 2018 Corporate Revolving Facility $ 604 $ 693 CDHI 3 251 Various project financing facilities 184 228 Other corporate facilities 294 193 Total $ 1,085 $ 1,365 Corporate Revolving Facility On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $ 330 million from $ 1.69 billion to approximately $ 2.02 billion . On August 12, 2019, we amended our Corporate Revolving Facility to extend the maturity of $ 150 million in revolving commitments from June 27, 2020 to March 8, 2023, and to reduce the commitments outstanding by $ 20 million to approximately $ 2.0 billion . The entire Corporate Revolving Facility matures on March 8, 2023. The Corporate Revolving Facility represents our primary revolving facility. Borrowings under the Corporate Revolving Facility bear interest, at our option, at either a base rate or LIBOR rate. Base rate borrowings shall be at the base rate, plus an applicable margin ranging from 1.00% to 1.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is defined as the higher of (i) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50% and (ii) the rate the administrative agent announces from time to time as its prime per annum rate. LIBOR rate borrowings shall be at the British Bankers’ Association Interest Settlement Rates for the interest period as selected by us as a one , two , three , six or, if agreed by all relevant lenders, nine or twelve month interest period, plus an applicable margin ranging from 2.00% to 2.25% . Interest payments are due on the last business day of each calendar quarter for base rate loans and the earlier of (i) the last day of the interest period selected or (ii) each day that is three months (or a whole multiple thereof) after the first day for the interest period selected for LIBOR rate loans. Letter of credit fees for issuances of letters of credit include fronting fees equal to that percentage per annum as may be separately agreed upon between us and the issuing lenders and a participation fee for the lenders equal to the applicable interest margin for LIBOR rate borrowings. Drawings under letters of credit shall be repaid within two business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We incur an unused commitment fee ranging from 0.25% to 0.50% on the unused amount of commitments under the Corporate Revolving Facility. The Corporate Revolving Facility does not contain any requirements for mandatory prepayments. However, we may voluntarily repay, in whole or in part, the Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be reborrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility without premium or penalty. The Corporate Revolving Facility is guaranteed and secured by certain of our current domestic subsidiaries and will also be additionally guaranteed by our future domestic subsidiaries that are required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving Facility ranks equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a minimum cash interest coverage ratio and a maximum net leverage ratio. CDHI We have a $ 300 million revolving facility related to CDHI which matures on October 2, 2021. Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI revolving facility was reduced to $125 million on June 28, 2019. The decrease in capacity did not have a material effect on our liquidity as alternative sources of liquidity are available to us. Our CDHI revolving facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements as well as fund the construction of our Washington Parish Energy Center. Borrowings under the CDHI revolving facility were $122 million at December 31, 2019, and bear interest, at our option, at either a base rate or LIBOR rate. Base rate borrowings shall be at the base rate, plus an applicable margin of 1.75% and LIBOR rate borrowings shall be at the LIBOR rate, plus an applicable margin of 2.75% . Other corporate facilities We have three unsecured letter of credit facilities with third party financial institutions totaling approximately $300 million . One of the facilities, with commitments totaling $150 million , matures partially in June 2020 and fully by December 2020. The other two facilities, with commitments totaling $50 million and approximately $100 million , mature in December 2023 and December 2021, respectively. Fair Value of Debt We record our debt instruments based on contractual terms, net of any applicable premium or discount and debt issuance costs. The following table details the fair values and carrying values of our debt instruments at December 31, 2019 and 2018 (in millions): 2019 2018 Fair Value Carrying Fair Value Carrying Value Senior Unsecured Notes $ 3,764 $ 3,663 $ 2,803 $ 3,036 First Lien Term Loans 3,238 3,167 2,877 2,976 First Lien Notes 2,929 2,835 2,299 2,400 Project financing, notes payable and other (1) 822 817 1,209 1,188 CCFC Term Loan 982 967 938 974 Revolving facilities 122 122 30 30 Total $ 11,857 $ 11,571 $ 10,156 $ 10,604 ____________ (1) Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP. Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loan are categorized as level 2 within the fair value hierarchy. Our revolving facilities and project financing, notes payable and other debt instruments are categorized as level 3 within the fair value hierarchy. We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy. |
Assets and Liabilities with Rec
Assets and Liabilities with Recurring Fair Value Measurements | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |
Assets and Liabilities with Recurring Fair Value Measurements | Assets and Liabilities with Recurring Fair Value Measurements Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do not have any cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Certain of our cash equivalents are classified within level 1 of the fair value hierarchy. Derivatives — The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties and customers for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future. We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs. The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and customers and the effect of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate. Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange. Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models, including the Black-Scholes option-pricing model, that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement at period end. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 and 2018 , by level within the fair value hierarchy: Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2019 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 784 $ — $ — $ 784 Commodity instruments: Commodity exchange traded derivatives contracts 872 — — 872 Commodity forward contracts (2) — 245 294 539 Interest rate hedging instruments — 12 — 12 Effect of netting and allocation of collateral (3)(4) (872 ) (131 ) (18 ) (1,021 ) Total assets $ 784 $ 126 $ 276 $ 1,186 Liabilities: Commodity instruments: Commodity exchange traded derivatives contracts 984 — — 984 Commodity forward contracts (2) — 285 123 408 Interest rate hedging instruments — 31 — 31 Effect of netting and allocation of collateral (3)(4) (984 ) (133 ) (18 ) (1,135 ) Total liabilities $ — $ 183 $ 105 $ 288 Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2018 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 168 $ — $ — $ 168 Commodity instruments: Commodity exchange traded derivatives contracts 933 — — 933 Commodity forward contracts (2) — 338 212 550 Interest rate hedging instruments — 40 — 40 Effect of netting and allocation of collateral (3)(4) (933 ) (262 ) (26 ) (1,221 ) Total assets $ 168 $ 116 $ 186 $ 470 Liabilities: Commodity instruments: Commodity exchange traded derivatives contracts 932 — — 932 Commodity forward contracts (2) — 549 220 769 Interest rate hedging instruments — 10 — 10 Effect of netting and allocation of collateral (3)(4) (932 ) (310 ) (26 ) (1,268 ) Total liabilities $ — $ 249 $ 194 $ 443 ___________ (1) As of December 31, 2019 and 2018 , we had cash equivalents of $573 million and $23 million included in cash and cash equivalents and $211 million and $145 million included in restricted cash, respectively. (2) Includes OTC swaps and options. (3) We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 10 for further discussion of our derivative instruments subject to master netting arrangements. (4) Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $112 million , $2 million and nil , respectively, at December 31, 2019 . Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $(1) million , $48 million and nil , respectively, at December 31, 2018 . At December 31, 2019 and 2018 , the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at December 31, 2019 and 2018 : Quantitative Information about Level 3 Fair Value Measurements December 31, 2019 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts (1) $ 158 Discounted cash flow Market price (per MWh) $4.85 — $184.15/MWh Power Congestion Products $ 17 Discounted cash flow Market price (per MWh) $(10.32)— $20.00/MWh Natural Gas Contracts $ (20 ) Discounted cash flow Market price (per MMBtu) $1.73 — $6.45/MMBtu Quantitative Information about Level 3 Fair Value Measurements December 31, 2018 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts (1) $ 36 Discounted cash flow Market price (per MWh) $2.12 — $227.98/MWh Power Congestion Products $ 26 Discounted cash flow Market price (per MWh) $(11.71) — $11.88/MWh Natural Gas Contracts $ (73 ) Discounted cash flow Market price (per MMBtu) $0.75 — $8.87/MMBtu ___________ (1) Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy. The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the years ended December 31, 2019 , 2018 and 2017 (in millions): 2019 2018 2017 Balance, beginning of period $ (8 ) $ 197 $ 416 Realized and mark-to-market gains (losses): Included in net income (loss): Included in operating revenues (1) 171 (88 ) 32 Included in fuel and purchased energy expense (2) (21 ) (45 ) 50 Change in collateral — — (17 ) Purchases, issuances and settlements: Purchases 5 18 4 Issuances (3 ) (2 ) (1 ) Settlements 56 (86 ) (179 ) Transfers in and/or out of level 3 (3) : Transfers into level 3 (4) 1 — (2 ) Transfers out of level 3 (5) (30 ) (2 ) (106 ) Balance, end of period $ 171 $ (8 ) $ 197 Change in unrealized gains (losses) relating to instruments still held at end of period $ 150 $ (133 ) $ 82 ___________ (1) For power contracts and other power-related products, included on our Consolidated Statements of Operations. (2) For natural gas and power contracts, swaps and options, included on our Consolidated Statements of Operations. (3) We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 during the years ended December 31, 2019 , 2018 and 2017 . (4) We had $1 million in gains, nil and $(2) million in losses transferred out of level 2 into level 3 for the years ended December 31, 2019 , 2018 and 2017 , respectively. (5) We had $30 million , $2 million and $104 million in gains transferred out of level 3 into level 2 during the years ended December 31, 2019 , 2018 and 2017 , respectively, due to changes in market liquidity in various power markets and $2 million in gains transferred out of level 3 during the years ended December 31, 2017, to other assets following the election of the normal purchase normal sales exemption and the discontinuance of derivative accounting treatment as of the date of this election for certain commodity contracts. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Derivative Instruments Types of Derivative Instruments and Volumetric Information Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, fuel oil, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power or natural gas price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels. We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading results were not material for the years ended December 31, 2019 , 2018 and 2017 . Interest Rate Hedging Instruments — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate hedging instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of December 31, 2019 , the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 6 years. As of December 31, 2019 and 2018 , the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions): Derivative Instruments Notional Amounts 2019 2018 Unit of Measure Power (MWh) (184 ) (161 ) Million MWh Natural gas (MMBtu) 1,063 1,045 Million MMBtu Environmental credits (Tonnes) 26 13 Million Tonnes Interest rate hedging instruments $ 4.8 $ 4.5 Billion U.S. dollars Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of December 31, 2019 , was $153 million for which we have posted collateral of $93 million by posting margin deposits, letters of credit or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $3 million related to our derivative liabilities would be required and that no counterparty could request immediate, full settlement. Accounting for Derivative Instruments We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities. Cash Flow Hedges — We currently apply hedge accounting to our interest rate hedging instruments. We report the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Prior to January 1, 2019, gains and losses due to ineffectiveness on interest rate hedging instruments were recognized in earnings as a component of interest expense. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value will be recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects earnings or until it is determined that the forecasted transaction is probable of not occurring. Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for physical and financial power and Heat Rate and commodity option activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense. Derivatives Included on Our Consolidated Balance Sheets We offset fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Balance Sheets that are executed with the same counterparty under master netting arrangements. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post and/or receive cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. The following tables present the fair values of our derivative instruments and our net exposure after offsetting amounts subject to a master netting arrangement with the same counterparty to our derivative instruments recorded on our Consolidated Balance Sheets by location and hedge type at December 31, 2019 and 2018 (in millions): December 31, 2019 Gross Amounts of Assets and (Liabilities) Gross Amounts Offset on the Consolidated Balance Sheets Net Amount Presented on the Consolidated Balance Sheets (1) Derivative assets: Commodity exchange traded derivatives contracts $ 727 $ (727 ) $ — Commodity forward contracts 262 (108 ) 154 Interest rate hedging instruments 2 — 2 Total current derivative assets (2) $ 991 $ (835 ) $ 156 Commodity exchange traded derivatives contracts 145 (145 ) — Commodity forward contracts 277 (41 ) 236 Interest rate hedging instruments 10 — 10 Total long-term derivative assets (2) $ 432 $ (186 ) $ 246 Total derivative assets $ 1,423 $ (1,021 ) $ 402 Derivative (liabilities): Commodity exchange traded derivatives contracts $ (830 ) $ 830 $ — Commodity forward contracts (321 ) 109 (212 ) Interest rate hedging instruments (13 ) — (13 ) Total current derivative (liabilities) (2) $ (1,164 ) $ 939 $ (225 ) Commodity exchange traded derivatives contracts (154 ) 154 — Commodity forward contracts (87 ) 42 (45 ) Interest rate hedging instruments (18 ) — (18 ) Total long-term derivative (liabilities) (2) $ (259 ) $ 196 $ (63 ) Total derivative liabilities $ (1,423 ) $ 1,135 $ (288 ) Net derivative assets (liabilities) $ — $ 114 $ 114 December 31, 2018 Gross Amounts of Assets and (Liabilities) Gross Amounts Offset on the Consolidated Balance Sheets Net Amount Presented on the Consolidated Balance Sheets (1) Derivative assets: Commodity exchange traded derivatives contracts $ 820 $ (820 ) $ — Commodity forward contracts 341 (229 ) 112 Interest rate hedging instruments 30 — 30 Total current derivative assets (3) $ 1,191 $ (1,049 ) $ 142 Commodity exchange traded derivatives contracts 113 (113 ) — Commodity forward contracts 209 (59 ) 150 Interest rate hedging instruments 10 — 10 Total long-term derivative assets (3) $ 332 $ (172 ) $ 160 Total derivative assets $ 1,523 $ (1,221 ) $ 302 Derivative (liabilities): Commodity exchange traded derivatives contracts $ (764 ) $ 764 $ — Commodity forward contracts (576 ) 277 (299 ) Interest rate hedging instruments (4 ) — (4 ) Total current derivative (liabilities) (3) $ (1,344 ) $ 1,041 $ (303 ) Commodity exchange traded derivatives contracts (168 ) 168 — Commodity forward contracts (193 ) 59 (134 ) Interest rate hedging instruments (6 ) — (6 ) Total long-term derivative (liabilities) (3) $ (367 ) $ 227 $ (140 ) Total derivative liabilities $ (1,711 ) $ 1,268 $ (443 ) Net derivative assets (liabilities) $ (188 ) $ 47 $ (141 ) ____________ (1) At December 31, 2019 and 2018 , we had $191 million and $244 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Balance Sheets primarily related to initial margin requirements. (2) At December 31, 2019 , current and long-term derivative assets are shown net of collateral of $(4) million and $(4) million , respectively, and current and long-term derivative liabilities are shown net of collateral of $108 million and $14 million , respectively. (3) At December 31, 2018 , current and long-term derivative assets are shown net of collateral of $(58) million and $(8) million , respectively, and current and long-term derivative liabilities are shown net of collateral of $49 million and $64 million , respectively. December 31, 2019 December 31, 2018 Fair Value of Derivative Assets Fair Value of Derivative Liabilities Fair Value of Derivative Assets Fair Value of Derivative Liabilities Derivatives designated as cash flow hedging instruments: Interest rate hedging instruments $ 12 $ 29 $ 40 $ 10 Total derivatives designated as cash flow hedging instruments $ 12 $ 29 $ 40 $ 10 Derivatives not designated as hedging instruments: Commodity instruments $ 390 $ 257 $ 262 $ 433 Interest rate hedging instruments — 2 — — Total derivatives not designated as hedging instruments $ 390 $ 259 $ 262 $ 433 Total derivatives $ 402 $ 288 $ 302 $ 443 Derivatives Included on Our Consolidated Statements of Operations Changes in the fair values of our derivative instruments are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Statements of Operations as a component of mark-to-market activity within our earnings. The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Statements of Operations for the years ended December 31, 2019 , 2018 and 2017 (in millions): 2019 2018 2017 Realized gain (loss) (1)(2) Commodity derivative instruments $ 256 $ 193 $ 7 Total realized gain $ 256 $ 193 $ 7 Mark-to-market gain (loss) (3) Commodity derivative instruments $ 278 $ (208 ) $ (171 ) Interest rate hedging instruments (3 ) 3 2 Total mark-to-market gain (loss) $ 275 $ (205 ) $ (169 ) Total activity, net $ 531 $ (12 ) $ (162 ) ___________ (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. (2) Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions. (3) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure. 2019 2018 2017 Realized and mark-to-market gain (loss) (1) Derivatives contracts included in operating revenues (2)(3) $ 816 $ (369 ) $ (69 ) Derivatives contracts included in fuel and purchased energy expense (2)(3) (282 ) 354 (95 ) Interest rate hedging instruments included in interest expense (3 ) 3 2 Total activity, net $ 531 $ (12 ) $ (162 ) ___________ (1) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure. (2) Does not include the realized value associated with derivative instruments that settle through physical delivery. (3) Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions. Derivatives Included in OCI and AOCI The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the years ended December 31, 2019 , 2018 and 2017 (in millions): Gain (Loss) Recognized in OCI (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) (3)(4) 2019 2018 2017 2019 2018 2017 Affected Line Item on the Consolidated Statements of Operations Interest rate hedging instruments (1)(2) $ (41 ) $ 45 $ 21 $ (1 ) $ (5 ) $ (43 ) Interest expense Interest rate hedging instruments (1)(2) 1 1 5 (1 ) (1 ) (5 ) Depreciation expense Total $ (40 ) $ 46 $ 26 $ (2 ) $ (6 ) $ (48 ) ____________ (1) We recorded a gain of $1 million on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the years ended December 31, 2018 and 2017. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings. (2) We recorded an income tax benefit of $2 million and income tax expense of $5 million and $6 million for the years ended December 31, 2019 , 2018 and 2017 , respectively, in AOCI related to our cash flow hedging activities. (3) Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $72 million , $34 million and $72 million at December 31, 2019 , 2018 and 2017 , respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million , $ 3 million and $ 6 million at December 31, 2019 , 2018 and 2017 , respectively. (4) Includes losses of $2 million , $1 million and nil that were reclassified from AOCI to interest expense for the years ended December 31, 2019 , 2018 and 2017 , respectively, where the hedged transactions became probable of not occurring. We estimate that pre-tax net losses of $26 million would be reclassified from AOCI into interest expense during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative) will be for the next 12 months. |
Use of Collateral
Use of Collateral | 12 Months Ended |
Dec. 31, 2019 | |
Use of Collateral [Abstract] | |
Use of Collateral | Use of Collateral We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of our interest rate hedging instruments in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements. The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of December 31, 2019 and 2018 (in millions): 2019 2018 Margin deposits (1) $ 432 $ 343 Natural gas and power prepayments 29 31 Total margin deposits and natural gas and power prepayments with our counterparties (2) $ 461 $ 374 Letters of credit issued $ 906 $ 1,166 First priority liens under power and natural gas agreements 42 92 First priority liens under interest rate hedging instruments 31 10 Total letters of credit and first priority liens with our counterparties $ 979 $ 1,268 Margin deposits posted with us by our counterparties (1)(3) $ 127 $ 52 Letters of credit posted with us by our counterparties 25 27 Total margin deposits and letters of credit posted with us by our counterparties $ 152 $ 79 ___________ (1) We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 10 for further discussion of our derivative instruments subject to master netting arrangements. (2) At December 31, 2019 and 2018 , $117 million and $79 million , respectively, were included in current and long-term derivative assets and liabilities, $336 million and $286 million , respectively, were included in margin deposits and other prepaid expense and $8 million and $9 million , respectively, were included in other assets on our Consolidated Balance Sheets. (3) At December 31, 2019 and 2018 , $3 million and $32 million , respectively, were included in current and long-term derivative assets and liabilities, $93 million and $20 million , respectively, were included in other current liabilities and $31 million and nil , respectively, were included in other long-term liabilities on our Consolidated Balance Sheets. Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Tax Cuts and Jobs Act (the “Act”) On December 22, 2017, the Act was signed into law resulting in significant changes from previous tax law. Some of the more meaningful provisions which affected us are: • a reduction in the U.S. federal corporate tax rate from 35% to 21% ; • limitation on the deduction of certain interest expense; • full expense deduction for certain business capital expenditures; • limitation on the utilization of NOLs arising after December 31, 2017; and • a system of taxing foreign-sourced income from multinational corporations. In December 2017, the SEC issued Staff Accounting Bulletin No. 118 “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” which allows a company up to one year to finalize and record the tax effects of the Act. We finalized the tax effect of the transition tax as of December 31, 2017 which did not have a material effect on our financial condition, results of operations or cash flows. During the year ended December 31, 2018, we finalized and recorded the remaining tax effects of the Act which did not have a material effect on our financial condition, results of operations or cash flows. Income Tax Expense (Benefit) The jurisdictional components of income from continuing operations before income tax expense (benefit), attributable to Calpine, for the years ended December 31, 2019 , 2018 and 2017 , are as follows (in millions): 2019 2018 2017 U.S. $ 836 $ 47 $ (358 ) International 32 27 27 Total $ 868 $ 74 $ (331 ) The components of income tax expense from continuing operations for the years ended December 31, 2019 , 2018 and 2017 , consisted of the following (in millions): 2019 2018 2017 Current: Federal $ (2 ) $ — $ (10 ) State 2 20 18 Foreign 3 (3 ) (14 ) Total current 3 17 (6 ) Deferred: Federal 66 (1 ) 5 State 28 (6 ) 6 Foreign 1 54 3 Total deferred 95 47 14 Total income tax expense $ 98 $ 64 $ 8 For the years ended December 31, 2019 , 2018 and 2017 , our income tax rates did not bear a customary relationship to statutory income tax rates, primarily as a result of the effect of our NOLs, valuation allowances and state income taxes. A reconciliation of the federal statutory rate of 21% and, prior to 2018, 35% to our effective rate from continuing operations for the years ended December 31, 2019 , 2018 and 2017 , is as follows: 2019 2018 2017 Federal statutory tax rate 21.0 % 21.0 % 35.0 % State tax expense, net of federal benefit 2.8 17.0 (6.0 ) Change in tax rate of net deferred tax asset — — (168.8 ) Valuation allowances offsetting tax rate change — — 168.8 Valuation allowances against future tax benefits (11.2 ) (31.7 ) (33.0 ) Valuation allowance related to foreign taxes — (138.3 ) 0.5 Decrease in foreign NOL due to change in ownership — 202.3 — Distributions from foreign affiliates and foreign taxes 0.2 6.6 (2.0 ) Change in unrecognized tax benefits — (8.0 ) 5.1 Disallowed compensation — 7.7 (0.6 ) Stock-based compensation — (1.5 ) (0.9 ) Equity earnings 0.1 1.4 (0.8 ) Merger Related Fees/Expenses — 12.7 — Depletion in excess of basis (0.3 ) (4.0 ) — Other differences (1.3 ) 1.3 0.3 Effective income tax rate 11.3 % 86.5 % (2.4 )% Deferred Tax Assets and Liabilities The components of deferred income taxes as of December 31, 2019 and 2018 , are as follows (in millions): 2019 2018 Deferred tax assets: NOL and credit carryforwards $ 1,731 $ 1,595 Taxes related to risk management activities and derivatives 18 7 Reorganization items and impairments 73 166 Other differences 62 101 Deferred tax assets before valuation allowance 1,884 1,869 Valuation allowance (873 ) (1,000 ) Total deferred tax assets 1,011 869 Deferred tax liabilities: Property, plant and equipment (1,125 ) (890 ) Total deferred tax liabilities (1,125 ) (890 ) Net deferred tax asset (liability) (114 ) (21 ) Less: Non-current deferred tax liability (116 ) (22 ) Deferred income tax asset, non-current $ 2 $ 1 Intraperiod Tax Allocation — In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of a tax expense (benefit) to continuing operations due to current OCI gains (losses) with an offsetting amount recognized in OCI. The intraperiod tax allocation included in continuing operations is nil , $1 million and $6 million for the years ended December 31, 2019 , 2018 and 2017 . NOL Carryforwards — As of December 31, 2019 , our NOL carryforwards consisted primarily of federal NOL carryforwards of approximately $7.1 billion , of which the majority expire between 2024 and 2037 , and NOL carryforwards in 25 states and the District of Columbia totaling approximately $3.2 billion , which expire between 2020 and 2039 . A substantial portion of our federal and state NOLs are offset with a valuation allowance. Certain of the state NOL carryforwards may be subject to limitations on their annual usage. As a result of the ownership change associated with the Merger, our ability to utilize the NOL carryforwards are subject to limitations. Additionally, our state NOLs available to offset future state income could materially decrease which would be offset by an equal and offsetting adjustment to the existing valuation allowance. Given the offsetting adjustments to the existing valuation allowance, the ownership change is not expected to have a material adverse effect on our Consolidated Financial Statements. As a result of the Merger, our Canadian NOLs, which comprised all of our foreign NOLs, are no longer available to us. This resulted in a decrease of approximately $58 million in the deferred tax asset and a related charge to deferred tax expense during the year ended December 31, 2018. Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to IRS examination regardless of when the NOLs were generated. Any adjustment of state or federal returns could result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs. We are currently under various state income tax audits for various periods. Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies. As of December 31, 2019 , we have provided a valuation allowance of approximately $ 873 million on certain federal and state tax jurisdiction deferred tax assets to reduce the amount of these assets to the extent necessary to result in an amount that is more likely than not to be realized. The net change in our valuation allowance was a decrease of $127 million for the year ended December 31, 2019 . Limitation on Deductions of Net Business Interest Expense — On November 26, 2018, the U.S. Treasury Department released proposed regulations which would limit the current deductibility of net business interest expense. The proposed regulations would be applicable for taxable years ending after the date on which the regulations become final. Companies have the discretion to apply the proposed regulations, but must apply all such provisions of the proposed regulations on a consistent basis. As of December 31, 2019, we have not elected to apply the proposed regulations for the 2018 or 2019 tax years and we do not expect the application of the final regulations will have a material effect on our Consolidated Financial Statements. Unrecognized Tax Benefits At December 31, 2019 , we had unrecognized tax benefits of $29 million . If recognized, $17 million of our unrecognized tax benefits could affect the annual effective tax rate and $12 million , related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no effect to our effective tax rate. We had accrued interest and penalties of $3 million and $2 million for income tax matters at December 31, 2019 and 2018 , respectively. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Statements of Operations and recorded $1 million , $(2) million and $(8) million for the years ended December 31, 2019 , 2018 and 2017 , respectively. A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2019 , 2018 and 2017 , is as follows (in millions): 2019 2018 2017 Balance, beginning of period $ (28 ) $ (38 ) $ (59 ) Increases related to prior year tax positions — (7 ) — Decreases related to prior year tax positions — 17 11 Increases related to current year tax positions (1 ) — (2 ) Decreases related to change in tax rate of net deferred tax asset — — 12 Balance, end of period $ (29 ) $ (28 ) $ (38 ) |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2019 | |
Share-based Payment Arrangement [Abstract] | |
Stock-Based Compensation | Stock-Based Compensation Calpine Equity Incentive Plans Prior to the effective date of the Merger on March 8, 2018, the Calpine Equity Incentive Plans provided for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. Subsequent to the merger, we do not issue share-based awards. As a result of the Merger, the outstanding share-based awards were treated as follows during the first quarter of 2018: • all restricted stock and restricted stock units were vested and canceled and the holders received a cash payment equal to a share price of $15.25 per share less any applicable withholding taxes; • all vested and unvested stock options were vested (in the case of unvested stock options) and canceled and the holders of the stock options received a cash payment equal to the intrinsic value based on a share price of $15.25 per share less any applicable withholding taxes; and • all Performance Share Units (“PSUs”), including the PSUs awarded in 2015 for the measurement period of January 1, 2015 through December 31, 2017, were vested and canceled in exchange for a cash payment with the payout value based on the greater of target value or actual performance over the truncated period using a share price of $15.25 per share less any applicable withholding taxes. The amount of cash transferred to repurchase the share-based awards associated with our equity classified share-based awards totaled $79 million and was recorded to additional paid-in capital on our Consolidated Balance Sheet for the year ended December 31, 2018. The amount of unrecognized compensation related to our equity classified share-based awards that we recognized in connection with the shortened service period associated with the completion of the Merger was $35 million for the year ended December 31, 2018, which did not include any incremental compensation cost as the amount paid did not exceed the fair value of the equity classified share-based awards at the effective time of the Merger. The total stock-based compensation expense for our equity classified share-based awards was $41 million and $36 million for the years ended December 31, 2018 and 2017, respectively. The amount of cash transferred to repurchase the share-based awards associated with our liability classified share-based awards totaled $25 million and was recorded to the associated liability in other long-term liabilities on our Consolidated Balance Sheet for the year ended December 31, 2018. The amount of unrecognized compensation related to our liability classified share-based awards that we recognized in connection with the shortened implied service period associated with the completion of the Merger was $16 million for the year ended December 31, 2018. The total stock-based compensation expense for our liability classified share-based awards was $ 16 million and $ 6 million for the years ended December 31, 2018 and 2017, respectively. The total intrinsic value of our employee stock options exercised was $11 million and nil for the years ended December 31, 2018 and 2017, respectively. The total cash proceeds received from our employee stock options exercised was nil for each of the years ended December 31, 2018 and 2017, respectively. The total fair value of our restricted stock and restricted stock units that vested during the years ended December 31, 2018 and 2017 was approximately $88 million and $23 million , respectively. |
Defined Contribution and Define
Defined Contribution and Defined Benefit Plans | 12 Months Ended |
Dec. 31, 2019 | |
Defined Contribution and Defined Benefit Plans [Abstract] | |
Defined Contribution and Defined Benefit Plans | Defined Contribution and Defined Benefit Plans We maintain two defined contribution savings plans that are intended to be tax exempt under Sections 401(a) and 501(a) of the IRC. Our non-union plan generally covers employees who are not covered by a collective bargaining agreement, and our union plan covers employees who are covered by a collective bargaining agreement. In 2018, we added an enhanced feature to our defined contribution plan for non-union employees consisting of a non-elective contribution for certain eligible employees who are active employees as of December 31st. We recorded expenses for these plans of approximately $20 million , $20 million and $14 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. Employer matching contributions are 100% of the first 5% of compensation a participant defers for the non-union plan. The employee deferral limit is 75% of eligible compensation under both plans. We also maintain defined benefit pension plans whereby retirement benefits are primarily a function of age attained, years of participation, years of service, vesting and level of compensation. Only approximately 4% of our employees are eligible to participate in a defined benefit pension plan. As of December 31, 2019 and 2018 , there were approximately $26 million and $19 million in plan assets and approximately $33 million and $27 million in pension liabilities, respectively. Our net pension liability recorded on our Consolidated Balance Sheets as of December 31, 2019 and 2018 , was approximately $7 million and $8 million , respectively. For the years ended December 31, 2019 , 2018 and 2017 , we recognized net periodic benefit costs of approximately $1 million , $1 million and $1 million , respectively. Our net periodic benefit cost is included in operating and maintenance expense on our Consolidated Statements of Operations. As of December 31, 2019 and 2018 , the total amount recognized in AOCI for actuarial losses related to pension obligation was approximately $6 million and $4 million , respectively. In making our estimates of our pension obligation and related costs, we utilize discount rates, rates of compensation increases and rates of return on our assets that we believe are reasonable. Due to the relatively small size of our pension liability (which is not considered material), significant changes in these assumptions would not have a material effect on our pension liability. During 2019 and 2018 , we made contributions of approximately $4 million and $1 million , respectively, and estimated contributions to the pension plan are expected to be approximately nil in 2020. Estimated future benefit payments to participants in each of the next five years are expected to be approximately $1 million in each year. |
Capital Structure
Capital Structure | 12 Months Ended |
Dec. 31, 2019 | |
Capital Structure [Abstract] | |
Capital Structure | Capital Structure On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub merged with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent. On March 8, 2018, we completed the Merger contemplated in the Merger Agreement. At the effective time of the Merger, each share of Calpine common stock outstanding as of immediately prior to the effective time of the Merger (excluding certain shares as described in the Merger Agreement) ceased to be outstanding and was converted into the right to receive $15.25 per share in cash or approximately $5.6 billion in total. Also at the effective time of the Merger, the common stock of Merger Sub became the new common stock of Calpine Corporation. Common Stock Our authorized common stock consists of 5,000 shares of Calpine Corporation common stock as of December 31, 2019 and 2018 . Common stock issued as of December 31, 2019 and 2018 , was 105.2 shares, at a par value of $0.001 per share. Common stock outstanding as of December 31, 2019 and 2018 , was 105.2 shares. The table below summarizes our common stock activity for the years ended December 31, 2019 , 2018 and 2017 . Shares Issued Shares Held in Treasury Shares Outstanding Balance, December 31, 2016 359,627,113 (565,349 ) 359,061,764 Shares issued under Calpine Equity Incentive Plans 2,050,778 (596,451 ) 1,454,327 Balance, December 31, 2017 361,677,891 (1,161,800 ) 360,516,091 Shares issued under Calpine Equity Incentive Plans 355,805 (477,711 ) (121,906 ) Cancellation of Calpine Corporation common stock in accordance with the Merger Agreement (362,033,696 ) 1,639,511 (360,394,185 ) Conversion of Merger Sub common stock to Calpine Corporation common stock in accordance with the Merger Agreement 105.2 — 105.2 Balance, December 31, 2018 105.2 — 105.2 Shares issued under Calpine Equity Incentive Plans — — — Balance, December 31, 2019 105.2 — 105.2 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Long-Term Service Agreements As of December 31, 2019 , the total estimated commitments for LTSAs associated with turbines were approximately $217 million . These commitments are payable over the remaining terms of the respective agreements, which range from 1 to 20 years. LTSA future commitment estimates are based on the stated payment terms in the contracts at the time of execution. Certain of these agreements have terms that allow us to cancel the contracts for a fee. If we cancel such contracts, the estimated commitments remaining for LTSAs would be reduced. Production Royalties We are obligated under numerous geothermal contracts and right-of-way, easement and surface agreements. The geothermal contracts generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement and surface agreements are based on flat rates or adjusted based on consumer price index changes and are not material. Under the terms of most geothermal contracts, the royalties accrue as a percentage of power revenues. Certain properties also have net profits and overriding royalty interests that are in addition to the land base contract royalties. Some contracts contain clauses providing for minimum payments if production temporarily ceases or if production falls below a specified level. Production royalties for geothermal power plants for the years ended December 31, 2019 , 2018 and 2017 , were $24 million , $26 million and $25 million , respectively. Commodity Purchases We enter into commodity purchase contracts of various terms with third parties to supply fuel to our natural gas-fired power plants and power to our retail customers. The majority of our purchases are made in the spot market or under index-priced contracts. These contracts are accounted for as executory contracts and therefore not recognized as liabilities on our Consolidated Balance Sheet. At December 31, 2019 , we had future commitments for the purchase, transportation, or storage of commodities as detailed below (in millions): 2020 $ 402 2021 178 2022 121 2023 98 2024 41 Thereafter 103 Total $ 943 Guarantees and Indemnifications As part of our normal business operations, we enter into various agreements providing, or otherwise arranging, financial or performance assurance to third parties on behalf of our subsidiaries in the ordinary course of such subsidiaries’ respective business. Such arrangements include guarantees, standby letters of credit and surety bonds for power and natural gas purchase and sale arrangements, retail contracts, contracts associated with the development, construction, operation and maintenance of our fleet of power plants and our Accounts Receivable Sales Program. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. At December 31, 2019 , guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and the guarantee under our Account Receivable Sales Program and their respective expiration dates were as follows (in millions): Guarantee Commitments 2020 2021 2022 2023 2024 Thereafter Total Guarantee of subsidiary obligations (1) $ 30 $ 29 $ 24 $ 14 $ 13 $ 39 $ 149 Standby letters of credit (2)(3)(4) 1,015 32 — 38 — — 1,085 Surety bonds (4)(5)(6) 10 7 — — — 94 111 Guarantee under Accounts Receivable Sales Program (7) 222 — — — — — 222 Total $ 1,277 $ 68 $ 24 $ 52 $ 13 $ 133 $ 1,567 ____________ (1) Represents Calpine Corporation guarantees of certain power plant leases and related interest. All guaranteed finance leases are recorded on our Consolidated Balance Sheets. (2) The standby letters of credit disclosed above represent those disclosed in Note 8. (3) Letters of credit are renewed annually and as such all amounts are reflected in the year of letter of credit expiration. The related commercial obligations extend for multiple years, therefore, renewal of the letter of credit will likely follow the term of the associated commercial obligation. (4) These are contingent off balance sheet obligations. (5) The majority of surety bonds do not have expiration or cancellation dates. (6) As of December 31, 2019 , no cash collateral is outstanding related to these bonds. (7) Calpine has guaranteed the performance of Calpine Solutions under the Accounts Receivable Sales Program. The Accounts Receivable Sales Program expires on November 27, 2020 . We routinely arrange for the issuance of letters of credit and various forms of surety bonds to third parties in support of our subsidiaries’ contractual arrangements of the types described above and may guarantee the operating performance of some of our partially-owned subsidiaries up to our ownership percentage. The letters of credit issued under various credit facilities support risk management and other operational and construction activities. In the event a subsidiary were to fail to perform its obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make payment to the third party, we would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of one to five days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety bonds, such liabilities are included on our Consolidated Balance Sheets. Commercial Agreements — In connection with the purchase and sale of power, natural gas, environmental products and fuel oil to and from third parties with respect to the operation of our power plants and our retail subsidiaries, we may be required to guarantee a portion of the obligations of certain of our subsidiaries. We may also be required to guarantee performance obligations associated with our marketing, hedging, optimization and trading activities to manage our exposure to changes in prices for energy commodities. These guarantees may include future payment obligations and effectively guarantee our future performance under certain agreements. Asset Acquisition and Disposition Agreements — In connection with our purchase and sale agreements, we have frequently provided for indemnification to the counterparty for liabilities incurred as a result of a breach of a representation, warranty or covenant by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction. Other — Additionally, we and our subsidiaries from time to time assume other guarantee and indemnification obligations in conjunction with other transactions such as parts supply agreements, construction agreements, maintenance and service agreements and equipment lease agreements. These guarantee and indemnification obligations may include indemnification from personal injury or other claims by our employees as well as future payment obligations and effectively guarantee our future performance under certain agreements. Our potential exposure under guarantee and indemnification obligations can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Our total maximum exposure under our guarantee and indemnification obligations is not estimable due to uncertainty as to whether claims will be made or how any potential claim will be resolved. As of December 31, 2019 , there are no material outstanding claims related to our guarantee and indemnification obligations and we do not anticipate that we will be required to make any material payments under our guarantee and indemnification obligations. Litigation We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows. On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows. Environmental Matters We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material effect on our financial condition, results of operations or cash flows or that would significantly change our operations. |
Related Party Transactions (Not
Related Party Transactions (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions Disclosure [Text Block] | Related Party Transactions We have entered into various agreements with related parties associated with the operation of our business. A description of these related party transactions is provided below: Accounts Receivable Sales Program On December 1, 2016 , in conjunction with our acquisition of Calpine Solutions, we entered into the Accounts Receivable Sales Program which allows us to sell, at a discount, up to $ 250 million in certain trade accounts receivable, arising from the sale of power and natural gas, from Calpine Solutions to Calpine Receivables which in turn sells 100% of the receivables to an unaffiliated financial institution, subject to certain contractual limitations. The Accounts Receivable Sales Program expires on November 27, 2020 . Calpine Solutions services the receivables sold in exchange for a servicing fee which was not material for the years ended December 31, 2019 , 2018 and 2017 . We are not the primary beneficiary of Calpine Receivables and, accordingly, do not consolidate this entity in our Consolidated Financial Statements. See Note 7 for a further discussion of our unconsolidated VIEs. Any portion of the purchase price for the sold receivables which is not paid in cash is recorded as a note receivable. The note receivable is recorded at fair value and does not materially differ from the carrying value of the trade accounts receivable held prior to sale due to the short-term nature of the receivables and high credit quality of the retail customers involved. Receivables sold under the Accounts Receivable Sales Program are accounted for as sales and excluded from accounts receivable on our Consolidated Balance Sheets and reflected as cash provided by operating activities on our Consolidated Statements of Cash Flows. Calpine has guaranteed the performance of Calpine Solutions under the Accounts Receivable Sales Program. See Note 16 for a further description of our guarantees. Under the Accounts Receivable Sales Program, at December 31, 2019 and 2018 , we had $222 million and $238 million , respectively, in trade accounts receivable outstanding that were sold under the Accounts Receivable Sales Program and $38 million and $34 million , respectively, in notes receivable which was recorded on our Consolidated Balance Sheets. We sold an aggregate of approximately $2.3 billion , $2.4 billion and $2.2 billion in trade accounts receivable and recorded proceeds of approximately $2.3 billion , $2.3 billion and $2.2 billion during the years ended December 31, 2019 , 2018 and 2017 , respectively. Any losses incurred on the sale of trade accounts receivable are recorded in other (income) expense, net on our Consolidated Statements of Operations which were not material during the years ended December 31, 2019 , 2018 and 2017 . Lyondell — We have a ground lease agreement with Houston Refining LP (“Houston Refining”), a subsidiary of Lyondell, for our Channel Energy Center site from which we sell power, capacity and steam to Houston Refining under a PPA. We purchase refinery gas and raw water from Houston Refining under a facilities services agreement. One of the entities which obtained an ownership interest in Calpine through the Merger also has an ownership interest in Lyondell whereby they may significantly influence the management and operating policies of Lyondell. The terms of the PPA with Lyondell were negotiated prior to the Merger closing. During the year ended December 31, 2019 and 2018, we recorded $70 million and $76 million in operating revenues, respectively, and $14 million and $12 million in operating expenses, respectively, associated with Lyondell. At December 31, 2019 and 2018, the related party receivables and payables associated with this contract were immaterial. Other — Following the Merger, we have identified other related party contracts for the sale of power, capacity, steam and RECs which are entered into in the ordinary course of our business. Most of these contracts relate to the sale of commodities and capacity for varying tenors. We have also entered into a long-term land lease agreement with a related party. As of December 31, 2019 and 2018, the related party revenues, expenses, receivables and payables associated with these transactions were immaterial. |
Segment and Significant Custome
Segment and Significant Customer Information | 12 Months Ended |
Dec. 31, 2019 | |
Segment and Significant Customer Information [Abstract] | |
Segment and Significant Customer Information | Segment and Significant Customer Information We assess our business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. At December 31, 2019, our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result in changes to the composition of our geographic segments. Commodity Margin is a key operational measure of profit reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments (including a reconciliation of our Commodity Margin to income (loss) from operations by segment) for the periods indicated (in millions). Year Ended December 31, 2019 Wholesale West Texas East Retail Consolidation and Elimination Total Total operating revenues (1) $ 2,743 $ 3,081 $ 2,164 $ 4,093 $ (2,009 ) $ 10,072 Commodity Margin $ 1,151 $ 857 $ 924 $ 382 $ — $ 3,314 Add: Mark-to-market commodity activity, net and other (2) 219 154 46 (131 ) (34 ) 254 Less: Operating and maintenance expense 340 269 278 148 (34 ) 1,001 Depreciation and amortization expense 254 196 191 53 — 694 General and other administrative expense 35 53 45 17 — 150 Other operating expenses 31 6 42 — — 79 Impairment losses — 13 71 — — 84 (Gain) on sale of assets, net (4 ) — (6 ) — — (10 ) (Income) from unconsolidated subsidiaries — — (24 ) 2 — (22 ) Income from operations 714 474 373 31 — 1,592 Interest expense 609 (Gain) loss on extinguishment of debt and other (income) expense, net 95 Income before income taxes $ 888 Year Ended December 31, 2018 Wholesale West Texas East Retail Consolidation and Elimination Total Total operating revenues (1) $ 1,988 $ 2,860 $ 1,987 $ 3,976 $ (1,299 ) $ 9,512 Commodity Margin $ 1,060 $ 646 $ 970 $ 357 $ — $ 3,033 Add: Mark-to-market commodity activity, net and other (2) (165 ) (197 ) 40 84 (32 ) (270 ) Less: Operating and maintenance expense 348 272 269 163 (32 ) 1,020 Depreciation and amortization expense 269 237 180 53 — 739 General and other administrative expense 40 61 38 19 — 158 Other operating expenses 42 24 32 — — 98 Impairment losses — — 10 — — 10 (Income) from unconsolidated subsidiaries — — (26 ) 2 — (24 ) Income (loss) from operations 196 (145 ) 507 204 — 762 Interest expense 617 (Gain) loss on extinguishment of debt and other (income) expense, net 53 Income before income taxes $ 92 Year Ended December 31, 2017 Wholesale West Texas East Retail Consolidation and Elimination Total Total operating revenues (1) $ 1,881 $ 2,342 $ 1,658 $ 3,797 $ (926 ) $ 8,752 Commodity Margin $ 970 $ 552 $ 790 $ 396 $ — $ 2,708 Add: Mark-to-market commodity activity, net and other (2) (19 ) (174 ) (62 ) (10 ) (29 ) (294 ) Less: Operating and maintenance expense 361 308 302 138 (29 ) 1,080 Depreciation and amortization expense 240 208 201 75 — 724 General and other administrative expense 45 66 27 17 — 155 Other operating expenses 38 14 33 — — 85 Impairment losses 28 13 — — — 41 (Gain) on sale of assets, net — — (27 ) — — (27 ) (Income) from unconsolidated subsidiaries — — (24 ) 2 — (22 ) Income (loss) from operations 239 (231 ) 216 154 — 378 Interest expense 621 Debt modification and extinguishment costs and other (income) expense, net 70 Loss before income taxes $ (313 ) __________ (1) Includes intersegment revenues of $530 million , $488 million and $324 million in the West, $946 million , $573 million and $361 million in Texas, $522 million , $234 million and $237 million in the East and $11 million , $4 million , $4 million in Retail for the years ended December 31, 2019 , 2018 and 2017 , respectively. (2) Includes $1 million , nil and $(8) million of lease levelization and $78 million , $104 million and $178 million of amortization expense for the years ended December 31, 2019 , 2018 and 2017 , respectively. Significant Customers For the years ended December 31, 2019 , 2018 and 2017 , we had no significant customer that individually accounted for more than 10% of our annual consolidated revenues. |
Quarterly Consolidated Financia
Quarterly Consolidated Financial Data (unaudited) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Consolidated Financial Data (unaudited) | Quarterly Consolidated Financial Data (unaudited) Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including, but not limited to, our restructuring activities (including asset sales and dispositions), the completion of development projects, the timing and amount of curtailment of operations under the terms of certain PPAs, the degree of risk management and marketing, hedging, optimization and trading activities, energy commodity market prices and variations in levels of production. Furthermore, the majority of the dollar value of capacity payments under certain of our PPAs are received during the months of May through October. Quarter Ended December 31 September 30 June 30 March 31 (in millions) 2019 Operating revenues $ 2,082 $ 2,792 $ 2,599 $ 2,599 Income from operations $ 108 $ 682 $ 444 $ 358 Net income (loss) attributable to Calpine $ (156 ) $ 485 $ 266 $ 175 2018 Operating revenues $ 2,354 $ 2,890 $ 2,259 $ 2,009 Income (loss) from operations $ 105 $ 568 $ 417 $ (328 ) Net income (loss) attributable to Calpine $ (16 ) $ 272 $ 352 $ (598 ) |
Schedule of Valuation and Quali
Schedule of Valuation and Qualifying Accounts Disclosure | 12 Months Ended |
Dec. 31, 2019 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
Schedule of Valuation and Qualifying Accounts Disclosure | CALPINE CORPORATION AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS Description Balance at Beginning of Year Charged to Expense Charged to Other Accounts Deductions (1) Balance at End of Year (in millions) Year Ended December 31, 2019 Allowance for doubtful accounts $ 9 $ 6 $ (1 ) $ (5 ) $ 9 Deferred tax asset valuation allowance 1,000 (127 ) — — 873 Year Ended December 31, 2018 Allowance for doubtful accounts $ 9 $ 5 $ 1 $ (6 ) $ 9 Deferred tax asset valuation allowance 1,168 (168 ) — — 1,000 Year Ended December 31, 2017 Allowance for doubtful accounts $ 6 $ 4 $ 2 $ (3 ) $ 9 Deferred tax asset valuation allowance 1,581 (413 ) — — 1,168 ____________ (1) Represents write-offs of accounts considered to be uncollectible and previously reserved. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Consolidation | Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and include the accounts of all majority-owned subsidiaries that are not VIEs and all VIEs where we have determined we are the primary beneficiary. Intercompany transactions have been eliminated in consolidation. |
Equity Method Investments | We use the equity method of accounting to record our net interests in VIEs where we have determined that we are not the primary beneficiary, which include Greenfield LP, a 50% partnership interest and Calpine Receivables, a 100% membership interest. Our share of net income (loss) is calculated according to our equity ownership percentage or according to the terms of the applicable partnership agreement or limited liability company operating agreement. See Note 7 for further discussion of our VIEs and unconsolidated investments. We consolidate our VIEs where we determine that we have both the power to direct the activities of a VIE that most significantly affect the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE. We have determined that we hold the obligation to absorb losses and receive benefits in almost all of our VIEs where we hold the majority equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following primary activities which we believe to have a significant effect on a power plant’s financial performance: operations and maintenance, plant dispatch, and fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities for most of our majority-owned VIEs. Under our consolidation policy and under U.S. GAAP we also: • perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and • evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur, such as contractual changes where the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly affect the VIE’s economic performance or when there are other changes in the powers held by individual variable interest holders. |
Reclassification, Policy [Policy Text Block] | We have reclassified certain prior period amounts for comparative purposes. These reclassifications did not have a material effect on our financial condition, results of operations or cash flows. |
Jointly-Owned Plants | Certain of our subsidiaries own undivided interests in jointly-owned plants. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. We are responsible for our subsidiaries’ share of operating costs and direct expenses and include our proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of our Consolidated Financial Statements. |
Use of Estimates in Preparation of Financial Statements | The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Financial Statements. Actual results could differ from those estimates. |
Fair Value of Financial Instruments and Derivatives | See Note 8 for disclosures regarding the fair value of our debt instruments and Note 9 for disclosures regarding the fair values of our derivative instruments and related margin deposits and certain of our cash balances. Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loan are categorized as level 2 within the fair value hierarchy. Our revolving facilities and project financing, notes payable and other debt instruments are categorized as level 3 within the fair value hierarchy. We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy. Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do not have any cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Certain of our cash equivalents are classified within level 1 of the fair value hierarchy. Derivatives — The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties and customers for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future. We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs. The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and customers and the effect of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate. Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange. Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models, including the Black-Scholes option-pricing model, that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. |
Concentrations of Credit Risk | Financial instruments that potentially subject us to credit risk consist of cash and cash equivalents, restricted cash, accounts and notes receivable and derivative financial instruments. Certain of our cash and cash equivalents, as well as our restricted cash balances, are invested in money market accounts with investment banks that are not FDIC insured. We place our cash and cash equivalents and restricted cash in what we believe to be creditworthy financial institutions and certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Additionally, we actively monitor the credit risk of our counterparties and customers, including our receivable, commodity and derivative transactions. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the U.S. We generally have not collected collateral for accounts receivable from utilities and end-user customers; however, we may require collateral in the future. For financial and commodity derivative counterparties and customers, we evaluate the net accounts receivable, accounts payable and fair value of commodity contracts and may require security deposits, cash margin or letters of credit to be posted if our exposure reaches a certain level or their credit rating declines. Our counterparties and customers primarily consist of four categories of entities who participate in the energy markets: • financial institutions and trading companies; • regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers; • oil, natural gas, chemical and other energy-related industrial companies; and • commercial, industrial and residential retail customers. We have concentrations of credit risk with a few of our wholesale counterparties and retail customers relating to our sales of power and steam and our hedging, optimization and trading activities. For example, our wholesale business currently has contracts with investor owned California utilities which could be affected should they be found liable for recent wildfires in California and, accordingly, incur substantial costs associated with the wildfires. On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. We currently have several power plants that provide energy and energy-related products to PG&E under PPAs, many of which have PG&E collateral posting requirements. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through the application of collateral. We also currently have numerous other agreements with PG&E related to the operation of our power plants in Northern California, under which PG&E has continued to provide service since its bankruptcy filing. We cannot predict the ultimate outcome of this matter and continue to monitor the bankruptcy proceedings. We have exposure to trends within the energy industry, including declines in the creditworthiness of our counterparties and customers for our commodity and derivative transactions. Currently, certain of our counterparties and customers within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty and customer credit risk and monitors our net exposure with each counterparty or customer on a daily basis. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a credit risk threshold which is determined based on each counterparties’ and customer’s credit rating and evaluation of their financial statements. We utilize these thresholds to determine the need for additional collateral or restriction of activity with the counterparty or customer. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk. Currently, our wholesale counterparties and retail customers are performing and financially settling timely according to their respective agreements with the exception of certain retail customers where our credit exposure is not material. |
Cash and Cash Equivalents | We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. |
Restricted Cash | Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Balance Sheets |
Business Interruption Proceeds [Policy Text Block] | We record business interruption insurance proceeds when they are realizable and recorded approximately $11 million , $14 million and $27 million of business interruption proceeds in operating revenues for the years ended December 31, 2019 , 2018 , and 2017 , respectively. |
Accounts Receivable and Payable | Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest. Receivable balances greater than 30 days past due are reviewed for collectability, depending upon the nature of the customer, and if deemed uncollectible, are charged off against the allowance account after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best estimate to determine the required allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations. The accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging and optimization activities. Some of these receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a right of offset and settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off balance sheet credit exposure related to our customers. |
Inventory | Inventory primarily consists of spare parts, stored natural gas and fuel oil, environmental products and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or net realizable value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to operating and maintenance expense or capitalized to property, plant and equipment as the parts are utilized and consumed. |
Collateral | We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties and customers for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets previously subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility as collateral under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity hedge agreements” under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. The first priority liens have been granted in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. Certain of our interest rate hedging instruments relate to hedges of certain of our project financings collateralized by first priority liens on the underlying assets. See Note 11 for a further discussion on our amounts and use of collateral. |
Property, Plant and Equipment, Net | Property, plant, and equipment items are recorded at cost. We capitalize costs incurred in connection with the construction of power plants, the development of geothermal properties and the refurbishment of major turbine generator equipment. When capital improvements to leased power plants meet our capitalization criteria, they are capitalized as leasehold improvements and amortized over the shorter of the term of the lease or the economic life of the capital improvement. We expense maintenance when the service is performed for work that does not meet our capitalization criteria. Our current capital expenditures at our Geysers Assets are those incurred for proven reserves and reservoir replenishment (primarily water injection), pipeline and power generation assets and drilling of “development wells” as all drilling activity has been performed within the known boundaries of the steam reservoir. We have capitalized costs incurred during ownership consisting of additions, certain replacements or repairs when the repairs appreciably extend the life, increase the capacity or improve the efficiency or safety of the property. Such costs are expensed when they do not meet the above criteria. We purchased our Geysers Assets as a proven steam reservoir and all well costs, except well workovers and routine repairs and maintenance, have been capitalized since our purchase date. We depreciate our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis where we own the power plant or have a favorable option to purchase the power plant or take ownership of the power plant at conclusion of the lease term and a de minimis amount of the depreciable costs basis for componentized equipment. For our Geysers Assets, we typically assume no salvage values. We use the component depreciation method for our natural gas-fired power plant rotable parts, certain componentized balance of plant parts and our information technology equipment and the composite depreciation method for the other natural gas-fired power plant asset groups and Geysers Assets. Generally, upon normal retirement of assets under the composite depreciation method, the costs of such assets are retired against accumulated depreciation and no gain or loss is recorded. For the retirement of assets under the component depreciation method, generally, the costs and related accumulated depreciation of such assets are removed from our Consolidated Balance Sheets and any gain or loss is recorded as operating and maintenance expense. |
Goodwill and Intangible Assets, Policy [Policy Text Block] | Goodwill represents the excess of the purchase price over the fair value of the net assets acquired at the time of an acquisition. We assess the carrying amount of our goodwill annually for impairment during the third quarter and whenever the events or changes in circumstances indicate that the carrying value may not be recoverable. Our goodwill resulted from the acquisition of our retail business. As such, our goodwill balance of $242 million was allocated to our Retail segment. We did not record any changes in the carrying amount of our goodwill during the years ended December 31, 2019 and 2018. We record intangible assets, such as acquired contracts, customer relationships and trademark and trade name at their estimated fair values at acquisition. We use all information available to estimate fair values including quoted market prices, if available, and other widely accepted valuation techniques. Certain estimates and judgments are required in the application of the techniques used to measure fair value of our intangible assets, including estimates of future cash flows, selling prices, replacement costs, economic lives and the selection of a discount rate, which are not observable in the market and represent a level 3 measurement. All recognized intangible assets consist of rights and obligations with finite lives. |
Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments) | We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. We test goodwill and all intangible assets not subject to amortization for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test goodwill for impairment at the reporting unit level, which is identified one level below the Company’s operating segments for which discrete financial information is available and management regularly reviews the operating results. We perform an annual impairment assessment in the third quarter of each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of a reporting unit in which goodwill resides is less than its carrying value. For reporting units in which this assessment concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and we are not required to perform the goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, overall financial performance, and other relevant events and factors affecting the reporting unit. For reporting units in which the impairment assessment concludes that it is more likely than not that the fair value is less than its carrying value, we perform the goodwill impairment test, which compares the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and we are not required to perform additional analysis. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then we record an impairment loss equal to the difference not to exceed the goodwill balance assigned to the reporting unit. We did not record an impairment of our goodwill during the years ended December 31, 2019 , 2018 and 2017 . All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value. In order to estimate future cash flows, we consider historical cash flows, existing contracts, capacity prices and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material. When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material. |
Asset Retirement Obligation | We record all known asset retirement obligations for which the liability’s fair value can be reasonably estimated. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At December 31, 2019 and 2018 , our asset retirement obligation liabilities were $68 million and $63 million , respectively, primarily relating to land leases upon which our power plants are built and the requirement that the property meet specific conditions upon its return. |
Debt Issuance Costs | Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the related debt using a method that approximates the effective interest rate method. However, when the timing of debt transactions involve contemporaneous exchanges of cash between us and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, debt issuance costs are accounted for depending on whether the transaction qualifies as an extinguishment or modification, which requires us to either write-off the original debt issuance costs and capitalize the new issuance costs, or continue to amortize the original debt issuance costs and immediately expense the new issuance costs. Our debt issuance costs related to a recognized debt liability are presented as a direct deduction from the carrying amount of the related debt liability, which is consistent with the presentation of debt discounts. |
Revenue Recognition | Our operating revenues are comprised of the following: • power and steam revenue consisting of variable payments related to generation, retail power and gas sales activities, power revenues consisting of fixed and variable capacity payments not related to generation including capacity payments received from RTO and ISO capacity auctions, host steam, REC revenue from our Geysers Assets, other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues and realized settlements from our marketing, hedging, optimization and trading activities; • mark-to-market revenues from derivative instruments as a result of our marketing, hedging, optimization and trading activities; and • sales of natural gas and other service revenues. See Note 3 for further information related to our accounting for revenue from contracts with customers. Realized Settlements of Commodity Derivative Instruments — The realized value of power commodity sales and purchase contracts that are net settled or settled as gross sales and purchases, but could have been net settled, are reflected on a net basis and are included in Commodity revenue on our Consolidated Statements of Operations. Mark-to-Market Gain (Loss) — The changes in the mark-to-market value of power-based commodity derivative instruments are reflected on a net basis as a separate component of operating revenues. Gross vs. Net Accounting — We determine whether the financial statement presentation of revenues should be on a gross or net basis. Where we act as principal, we record settlement of our physical commodity contracts on a gross or net basis dependent upon whether the contract results in physical delivery of the underlying product. With respect to our physical executory contracts, where we do not take title to the commodities but receive a variable payment to convert natural gas into power and steam in a tolling operation, we record revenues on a net basis. Energy and Other Products Variable payments for power and steam that are based on generation, including retail sales of power, are recognized over time as the underlying commodity is generated or purchased and control is transferred to our customer upon transmission and delivery. Ancillary service revenues are also included within energy-related revenues and are recognized over time as the service is provided. For our power, steam and ancillary service contracts, we have elected the practical expedient that allows us to recognize revenue in the amount to which we have the right to invoice to the extent we determine that we have a right to consideration in an amount that corresponds directly with the value provided to date. To the extent this practical expedient cannot be utilized, we will recognize revenue over time based on the quantity of the commodity delivered to the customer for power and steam sales and over time as the service is provided for our ancillary service sales. Energy and other revenues also includes revenues generated from the sale of natural gas and environmental products, including RECs and are recognized at either a point in time or over time when control of the commodity has transferred. Revenues from the sale of RECs are primarily related to credits that are generated upon generation of renewable power from our Geysers Assets and are recognized over a period of time similar to the timing of the related energy sale. Revenues from sales of RECs or other environmental products that are not generated from our assets are recognized once all certifications have been completed and the credits are delivered to the customer at a point in time. Revenues from our natural gas sales are recognized at a point in time when delivery of the natural gas is provided. Revenues from natural gas and emission product sales are generally at the contracted transaction price, which may be fixed or index-based. Capacity Capacity revenues include fixed and variable capacity payments, which are based on generation volumes and include capacity payments received from RTO and ISO capacity auctions as well as contractual capacity under long-term PPAs. For these contracts, we have elected the practical expedient that allows us to recognize revenue in the amount to which we have the right to invoice to the extent we determine that we have a right to consideration in an amount that corresponds directly with the value provided to date. To the extent this practical expedient cannot be utilized, we will recognize revenue over time as the service is being provided to the customer. Performance Obligations and Contract Balances Certain of our contracts have multiple performance obligations. The revenues associated with each individual performance obligation is based on the relative stand-alone sales price of each good or service or, when not available, is based on a cost incurred plus margin approach. For a significant portion of our contracts with multiple performance obligations, management has applied the practical expedient that results in recognition of revenue commensurate with the invoiced amount and no allocation is required as all performance obligations are transferred over the same period of time. Certain of our contracts include volumetric optionality based on our customer’s needs. The transaction price within these contracts are based on a stand-alone sale price of the good or service being provided and revenue is recognized based on our customer’s usage. On a monthly basis, revenue is recognized based on estimated or actual usage by our customer at the transaction price. To the extent estimated usage is used in the recognition of revenue, revenues are adjusted for actual usage once known; however, this adjustment is not material to the revenues recognized. Generally, we have applied the practical expedient that allows us to recognize revenue based on the invoiced amount for these contracts. Changes in estimates for our contracts are not material and revisions to estimates are recognized when the amounts can be reasonably estimated. Unbilled retail sales are based upon estimates of customer usage since the date of the last meter reading provided by the ISOs or electric distribution companies by applying the estimated revenue per KWh by customer class to the estimated number of KWhs delivered but not yet billed. Estimated amounts are adjusted when actual usage is known and billed. During the years ended December 31, 2019 and 2018, there were no significant changes to revenue amounts recognized in prior periods as a result of a change in estimates. Sales and other taxes we collect concurrent with revenue-producing activities are excluded from our operating revenues. Billing requirements for our wholesale customers generally result in billing customers on a monthly basis in the month following the delivery of the good or service. Once billed, payment is generally required within 20 days resulting in payment for the delivery of the good or service in the month following delivery of the good or service. Billing requirements for our retail customers are generally once every 30 days and may result in billed amounts relating to our retail customers extending up to 60 days. Based on the terms of our agreements, payment is generally received at or shortly after delivery of the good or service. Changes in accounts receivable relating to our customers is primarily due to the timing difference between payment and when the good or service is provided. During the years ended December 31, 2019 and 2018, there were no significant changes in accounts receivable other than normal billing and collection transactions and there were no material credit or impairment losses recognized relating to accounts receivable balances associated with contracts with customers. When we receive consideration from a customer prior to transferring goods or services to the customer under the terms of a contract, we record deferred revenue, which represents a contract liability. Such deferred revenue typically results from consideration received prior to the transfer of goods and services relating to our capacity contracts and the sale of RECs that are not generated from our power plants. Based on the nature of these contracts and the timing between when consideration is received and delivery of the good or service is provided, these contracts do not contain any material financing elements. |
Accounting for Derivative Instruments | We enter into a variety of derivative instruments including both exchange traded and OTC power and natural gas forwards, options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) and interest rate hedging instruments. We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for and are designated under the normal purchase normal sale exemption. Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes may not be available from sources external to us, in which case we rely on internally developed price estimates. See Note 10 for further discussion on our accounting for derivatives. Accounting for Derivative Instruments We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities. Cash Flow Hedges — We currently apply hedge accounting to our interest rate hedging instruments. We report the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Prior to January 1, 2019, gains and losses due to ineffectiveness on interest rate hedging instruments were recognized in earnings as a component of interest expense. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value will be recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects earnings or until it is determined that the forecasted transaction is probable of not occurring. Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for physical and financial power and Heat Rate and commodity option activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense. Derivatives Included on Our Consolidated Balance Sheets We offset fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Balance Sheets that are executed with the same counterparty under master netting arrangements. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post and/or receive cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. |
Fuel and Purchased Energy Expense | Fuel and purchased energy expense is comprised of the cost of natural gas and fuel oil purchased from third parties for the purposes of consumption in our power plants as fuel, the cost of power purchased from third parties for sale to retail customers, the cost of power and natural gas purchased from third parties for our marketing, hedging and optimization activities and realized settlements and mark-to-market gains and losses resulting from general market price movements against certain derivative natural gas and power contracts including financial natural gas transactions economically hedging anticipated future power sales that either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Realized and Mark-to-Market Expenses from Commodity Derivative Instruments Realized Settlements of Commodity Derivative Instruments — The realized value of natural gas commodity purchase and sales contracts that are net settled are reflected on a net basis and included in Commodity expense on our Consolidated Statements of Operations. Power purchase commodity contracts that result in the physical delivery of power, and that also supplement our power generation, are reflected on a gross basis and are included in Commodity expense on our Consolidated Statements of Operations. Mark-to-Market (Gain) Loss — The changes in the mark-to-market value of natural gas-based and certain power-based commodity derivative instruments are reflected on a net basis as a separate component of fuel and purchased energy expense. |
Operating and Maintenance Expense | Operating and maintenance expense primarily includes employee expenses, utilities, chemicals, repairs and maintenance (including equipment failure and major maintenance), insurance and property taxes. We recognize these expenses when the service is performed or in the period to which the expense relates. |
Income Taxes | Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis and tax credit and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that includes the enactment date. We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. |
New Accounting Pronouncements | Leases — On January 1, 2019, we adopted Accounting Standards Update 2016-02, “Leases” (“Topic 842”). The comprehensive new lease standard superseded all existing lease guidance. The standard requires that a lessee should recognize a right-of-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. For lessors, the accounting for leases under Topic 842 remained substantially unchanged. The standard also requires expanded disclosures surrounding leases. We adopted the standards under Topic 842 using the modified retrospective method and elected a number of the practical expedients in our implementation of Topic 842. The key change that affected us relates to our accounting for operating leases for which we are the lessee that were historically off-balance sheet. The impact of adopting the standards resulted in the recognition of a right-of-use asset and lease obligation liability of $191 million on our Consolidated Balance Sheet on January 1, 2019, exclusive of previously recognized lease balances. The implementation of Topic 842 did not have a material effect on our Consolidated Statement of Operations or Consolidated Statement of Cash Flows for the year ended December 31, 2019. See Note 4 for a discussion of the practical expedients we elected and additional disclosures required by Topic 842. Derivatives and Hedging — In August 2017, the FASB issued Accounting Standards Update 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” The standard better aligns an entity’s hedging activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results in the financial statements. The standard will prospectively make hedge accounting easier to apply to hedging activities and also enhances disclosure requirements for how hedge transactions are reflected in the financial statements when hedge accounting is elected. We adopted Accounting Standards Update 2017-12 in the first quarter of 2019 which did not have a material effect on our financial condition, results of operations or cash flows. Fair Value Measurements — In August 2018, the FASB issued Accounting Standards Update 2018-13, “Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement.” The standard removes, modifies and adds disclosures about fair value measurements and is effective for fiscal years beginning after December 15, 2019. The changes required by this standard to remove or modify disclosures may be early adopted with adoption of the additional disclosures required by this standard delayed until their effective date. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. Income Taxes — In December 2019, the FASB issued Accounting Standards Update 2019-12, “Simplifying the Accounting for Income Taxes.” The standard is intended to simplify the accounting for income taxes by removing certain exceptions and improve consistent application by clarifying guidance related to the accounting for income taxes. The standard is effective for fiscal years beginning after December 15, 2020. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. |
Lessee, Leases [Policy Text Block] | Accounting for Leases – Lessee We evaluate contracts for lease accounting at contract inception and assess lease classification at the lease commencement date. For our leases, we recognize a right-of-use asset and corresponding lease obligation liability at the lease commencement date where the lease obligation liability is measured at the present value of the minimum lease payments. For our operating leases, the amortization of the right-of-use asset and the accretion of our lease obligation liability result in a single straight-line expense recognized over the lease term. We determine the discount rate associated with our operating and finance leases using our incremental borrowing rate at lease commencement. For our operating leases, we use an interest rate commensurate with the interest rate to borrow on a collateralized basis over a similar term with an amount equal to the lease payments. Factors management considers in the calculation of the discount rate include the amount of the borrowing, the lease term including options that are reasonably certain of exercise, the current interest rate environment and the credit rating of the entity. For our finance leases, we use the interest rate commensurate with the interest rate for a project finance borrowing arrangement with a similar collateral package, repayment terms, restrictive covenants and guarantees. Our operating leases are primarily related to office space for our corporate and regional offices as well as land and operating related leases for our power plants. Additionally, one of our power plants is accounted for as an operating lease. Payments made by Calpine on this lease are recognized on a straight-line basis with capital improvements associated with our leased power plant deemed leasehold improvements that are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Several of our leases contain renewal options held by us to extend the lease term. The inclusion of these renewal periods in the lease term and in the minimum lease payments included in our lease liabilities is dependent on specific facts and circumstances for each lease and whether it is determined to be reasonably certain that we will exercise our option to extend the term. Our office, land and other operating leases do not contain any material restrictive covenants or residual value guarantees. We have entered into finance leases for certain power plants and related equipment with terms that range up to 30 years (including lease renewal options). The finance leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. In connection with our adoption of Topic 842 on January 1, 2019, we elected certain practical expedients that were available under the new lease standards including: • we elected not to separate lease and non-lease components for our current classes of underlying leased assets as the lessee; • we did not evaluate existing and expired land easements that were not previously accounted for as leases prior to January 1, 2019; and • we did not reassess the classification of leases, the accounting for initial direct costs or whether contractual arrangements contained a lease for all contracts that expired or commenced prior to January 1, 2019. Further, upon the adoption of Topic 842, we made an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. We do not have any material subleases associated with our operating and finance leases. |
Lessor, Leases [Policy Text Block] | Accounting for Leases – Lessor We apply lease accounting to PPAs that meet the definition of a lease and determine lease classification treatment at commencement of the agreement. We currently do not have any contracts which are accounted for as sales-type leases or direct financing leases and all of our leases as the lessor are classified as operating leases. As part of the implementation of Topic 842, we elected the practical expedient to not reassess leases that have commenced prior to January 1, 2019. Revenue from contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals (capacity payments) which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract. Our operating leases that have commenced contain terms extending through May 2042. These contracts also generally contain variable payment components based on generation volumes or operating efficiency over a period of time. Revenues associated with the variable payments are recognized over time as the goods or services are provided to the lessee. Our operating leases generally do not contain renewal or purchase options or residual value guarantees. We have elected to not separate our lease and non-lease components as the lease components reflect the predominant characteristics of these agreements. |
Commitments and Contingencies, Policy [Policy Text Block] | On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Schedule of Jointly Owned Utility Plants | The following table summarizes our proportionate ownership interest in jointly-owned power plants: As of December 31, 2019 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress (in millions, except percentages) Freestone Energy Center 75.0 % $ 379 $ (177 ) $ — Hidalgo Energy Center 78.5 % $ 250 $ (113 ) $ — |
Schedule of Components of Restricted Cash | The table below represents the components of our restricted cash as of December 31, 2019 and 2018 (in millions): 2019 2018 Current Non-Current Total Current Non-Current Total Debt service $ 58 $ 8 $ 66 $ 13 $ 8 $ 21 Construction/major maintenance 28 6 34 23 24 47 Security/project/insurance 209 31 240 120 — 120 Other 4 1 5 11 2 13 Total $ 299 $ 46 $ 345 $ 167 $ 34 $ 201 |
Schedule of Intangible Assets and Goodwill [Table Text Block] | As of December 31, 2019 and 2018 , the components of our intangible assets were as follows (in millions): 2019 2018 Lives Acquired contracts $ 444 $ 458 0 – 9 Years Customer relationships 445 445 7 – 14 Years Trademark and trade name 40 40 15 Years Other 4 88 39 – 44 Years 933 1,031 Less: Accumulated amortization 593 619 Intangible assets, net $ 340 $ 412 |
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block] | The estimated aggregate amortization expense of our intangible assets for the next five years is as follows (in millions): 2020 $ 44 2021 $ 39 2022 $ 36 2023 $ 28 2024 $ 28 |
Revenue from Contracts with C_2
Revenue from Contracts with Customers (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Revenue from Contracts with Customers [Abstract] | |
Disaggregation of Revenue [Table Text Block] | The following tables represent a disaggregation of our revenue for the years ended December 31, 2019 and 2018 by reportable segment (in millions). See Note 18 for a description of our segments. Year Ended December 31, 2019 Wholesale West Texas East Retail Elimination Total Third Party: Energy & other products $ 948 $ 1,406 $ 609 $ 1,694 $ — $ 4,657 Capacity 173 125 547 — — 845 Revenues relating to physical or executory contracts – third party $ 1,121 $ 1,531 $ 1,156 $ 1,694 $ — $ 5,502 Affiliate (1) : $ 44 $ 55 $ 99 $ 9 $ (207 ) $ — Revenues relating to leases and derivative instruments (2) $ 4,570 Total operating revenues $ 10,072 Year Ended December 31, 2018 Wholesale West Texas East Retail Elimination Total Third Party: Energy & other products $ 1,070 $ 1,500 $ 621 $ 1,857 $ — $ 5,048 Capacity 152 94 657 — — 903 Revenues relating to physical or executory contracts – third party $ 1,222 $ 1,594 $ 1,278 $ 1,857 $ — $ 5,951 Affiliate (1) : $ 30 $ 34 $ 89 $ 4 $ (157 ) $ — Revenues relating to leases and derivative instruments (2) $ 3,561 Total operating revenues $ 9,512 ___________ (1) Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine. (2) Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Statements of Operations. |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Lease, Cost [Table Text Block] | The components of our operating and finance lease expense are as follows for the year ended December 31, 2019 (in millions): December 31, 2019 Operating Leases Operating lease expense $ 46 Finance Leases Amortization of the right-of-use assets 8 Interest expense 8 Finance lease expense $ 16 Variable lease expense 9 Total lease expense $ 71 |
Finance Lease, Liability, Maturity [Table Text Block] | The following is a schedule by year of future minimum lease payments associated with our operating and finance leases together with the present value of the net minimum lease payments as of December 31, 2019 (in millions): Operating Leases (1) Finance Leases (2) 2020 $ 21 $ 16 2021 22 16 2022 20 15 2023 19 19 2024 18 8 Thereafter 185 26 Total minimum lease payments 285 100 Less: Amount representing interest 103 27 Total lease obligation 182 73 Less: current lease obligation 12 10 Long-term lease obligation $ 170 $ 63 ____________ (1) The lease liabilities associated with our operating leases as of December 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Balance Sheet. (2) The lease liabilities associated with our finance leases as of December 31, 2019 are included in debt, current portion and debt, net of current portion on our Consolidated Balance Sheet. |
Lessee, Operating Lease, Liability, Maturity [Table Text Block] | The following is a schedule by year of future minimum lease payments associated with our operating and finance leases together with the present value of the net minimum lease payments as of December 31, 2019 (in millions): Operating Leases (1) Finance Leases (2) 2020 $ 21 $ 16 2021 22 16 2022 20 15 2023 19 19 2024 18 8 Thereafter 185 26 Total minimum lease payments 285 100 Less: Amount representing interest 103 27 Total lease obligation 182 73 Less: current lease obligation 12 10 Long-term lease obligation $ 170 $ 63 ____________ (1) The lease liabilities associated with our operating leases as of December 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Balance Sheet. (2) The lease liabilities associated with our finance leases as of December 31, 2019 are included in debt, current portion and debt, net of current portion on our Consolidated Balance Sheet. |
Supplemental Balance Sheet Info Lessee [Table Text Block] | Supplemental balance sheet information related to our operating and finance leases is as follows as of December 31, 2019 (in millions, except lease term and discount rate): December 31, 2019 Operating leases (1) Right-of-use assets associated with operating leases $ 171 Finance leases (2) Property, plant and equipment, gross 212 Accumulated amortization (105 ) Property, plant and equipment, net $ 107 Weighted average remaining lease term (in years) Operating leases 17.5 Finance leases 6.8 Weighted average discount rate Operating leases 5.1 % Finance leases 8.0 % ____________ (1) The right-of-use assets associated with our operating leases as of December 31, 2019 are included in other assets on our Consolidated Balance Sheet. (2) The right-of-use assets associated with our finance leases as of December 31, 2019 are included in property, plant and equipment, net on our Consolidated Balance Sheet. |
Supplemental Cash Flow Lessee [Table Text Block] | Supplemental cash flow information related to our operating and finance leases is as follows for the period presented (in millions): December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 54 Operating cash flows from finance leases $ 8 Financing cash flows from finance leases $ 11 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 14 Finance leases $ — |
Lease Cost - Lessor [Table Text Block] | Revenue recognized related to fixed lease payments on our operating leases for the period presented is as follows (in millions): 2019 Operating Leases (1) Fixed lease payments $ 341 ____________ (1) Revenues associated with our operating leases are included in Commodity revenue and other revenue on our Consolidated Statement of Operations. December 31, 2019 Assets subject to contracts accounted for as operating leases Property, plant and equipment, gross $ 2,561 Accumulated depreciation (770 ) Property, plant and equipment, net (1) $ 1,791 ____________ (1) Our assets subject to contracts that are accounted for as operating leases primarily consist of our power plants subject to tolling contracts. |
Lessor, Operating Lease, Payments to be Received, Maturity [Table Text Block] | The total contractual future minimum lease rentals for our contracts that have commenced and are accounted for as operating leases at December 31, 2019 , are as follows (in millions): 2020 $ 286 2021 261 2022 226 2023 144 2024 50 Thereafter 236 Total $ 1,203 |
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block] | The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2018, are as follows (in millions): 2019 $ 342 2020 261 2021 257 2022 224 2023 141 Thereafter 239 Total $ 1,464 Lessee The following is a schedule by year of future minimum lease payments under operating and capital leases as of December 31, 2018 (in millions): Operating Leases (1) Capital Leases (2) 2019 $ 50 $ 40 2020 19 40 2021 20 38 2022 18 33 2023 17 27 Thereafter 192 92 Total minimum lease payments $ 316 270 Less: Amount representing interest 89 Present value of net minimum lease payments $ 181 ____________ (1) During the years ended December 31, 2018 and 2017, expense for operating leases amounted to $53 million and $50 million , respectively. (2) Includes a failed sale-leaseback transaction related to our Pasadena Power Plant. |
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block] | The following is a schedule by year of future minimum lease payments under operating and capital leases as of December 31, 2018 (in millions): Operating Leases (1) Capital Leases (2) 2019 $ 50 $ 40 2020 19 40 2021 20 38 2022 18 33 2023 17 27 Thereafter 192 92 Total minimum lease payments $ 316 270 Less: Amount representing interest 89 Present value of net minimum lease payments $ 181 ____________ (1) During the years ended December 31, 2018 and 2017, expense for operating leases amounted to $53 million and $50 million , respectively. (2) Includes a failed sale-leaseback transaction related to our Pasadena Power Plant. |
Property, Plant and Equipment_2
Property, Plant and Equipment, Net (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Property, Plant and Equipment, Net [Abstract] | |
Property, Plant and Equipment | As of December 31, 2019 and 2018 , the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions): 2019 2018 Depreciable Lives Buildings, machinery and equipment $ 16,510 $ 16,400 1.5 – 50 Years Geothermal properties 1,553 1,501 13 – 58 Years Other 291 286 3 – 50 Years 18,354 18,187 Less: Accumulated depreciation 6,851 6,832 11,503 11,355 Land 128 121 Construction in progress 332 966 Property, plant and equipment, net $ 11,963 $ 12,442 |
Variable Interest Entities an_2
Variable Interest Entities and Unconsolidated Investments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Variable Interest Entities and Unconsolidated Investments [Abstract] | |
Schedule of Equity Method Investments | At December 31, 2019 and 2018 , our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions): Ownership Interest as of December 31, 2019 2019 2018 Greenfield LP (1) 50% $ 66 $ 55 Whitby (2) —% — 15 Calpine Receivables 100% 4 6 Total investments in unconsolidated subsidiaries $ 70 $ 76 ____________ (1) Includes our share of accumulated other comprehensive income/loss related to interest rate hedging instruments associated with our unconsolidated subsidiary Greenfield LP’s debt. (2) On November 20, 2019, we sold our 50% interest in Whitby to a third party and recorded a gain on sale of assets, net of approximately $5 million . |
Income (Loss) From Unconsolidated Investments in Power Plants and Distributions | The following table sets forth details of our (income) loss from unconsolidated subsidiaries and distributions for the years indicated (in millions): (Income) loss from Unconsolidated Subsidiaries Distributions 2019 2018 2017 2019 2018 2017 Greenfield LP $ (13 ) $ (11 ) $ (14 ) $ — $ 48 $ 8 Whitby (1) (11 ) (15 ) (10 ) 26 5 20 Calpine Receivables 2 2 2 — — — Total $ (22 ) $ (24 ) $ (22 ) $ 26 $ 53 $ 28 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | Debt Our debt at December 31, 2019 and 2018 , was as follows (in millions): 2019 2018 Senior Unsecured Notes $ 3,663 $ 3,036 First Lien Term Loans 3,167 2,976 First Lien Notes 2,835 2,400 Project financing, notes payable and other 879 1,264 CCFC Term Loan 967 974 Finance lease obligations 73 105 Revolving facilities 122 30 Subtotal 11,706 10,785 Less: Current maturities 1,268 637 Total long-term debt $ 10,438 $ 10,148 |
Schedule of Maturities of Long-term Debt | Annual Debt Maturities Contractual annual principal repayments or maturities of debt instruments as of December 31, 2019 , are as follows (in millions): 2020 $ 1,269 2021 347 2022 230 2023 198 2024 2,030 Thereafter 7,771 Subtotal 11,845 Less: Debt issuance costs 114 Less: Discount 25 Total debt $ 11,706 |
Senior Unsecured Notes | Senior Unsecured Notes Our Senior Unsecured Notes are summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average (1) 2019 2018 2019 2018 2023 Senior Unsecured Notes (2) $ 623 $ 1,227 5.7 % 5.6 % 2024 Senior Unsecured Notes 479 599 5.7 5.7 2025 Senior Unsecured Notes 1,174 1,210 5.8 6.0 2028 Senior Unsecured Notes (2) 1,387 — 5.3 — Total Senior Unsecured Notes $ 3,663 $ 3,036 ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs. (2) On December 27, 2019, we used the proceeds from the issuance of our 2028 Senior Unsecured Notes (discussed below) to redeem approximately $613 million in aggregate principal amount of our 2023 Senior Unsecured Notes, plus accrued and unpaid interest. On January 21, 2020, we redeemed the remaining $623 million in aggregate principal amount of our 2023 Senior Unsecured Notes, which was included in debt, current portion on our Consolidated Balance Sheet at December 31, 2019, with the proceeds from the 2028 Senior Unsecured Notes, which was included in cash and cash equivalents on our Consolidated Balance Sheet at December 31, 2019 . We recorded approximately $24 million in loss on extinguishment of debt which is comprised of approximately $18 million of prepayment premiums and approximately $6 million associated with the write-off of unamortized debt issuance costs during the fourth quarter of 2019 associated with the redemption. |
Debt Instrument Redemption [Table Text Block] | Year Ended December 31, 2019 Year Ended December 31, 2018 Principal Repurchased Cash Paid Gain (loss) on Extinguishment of Debt Principal Repurchased Cash Paid Gain on Extinguishment of Debt (in million) 2023 Senior Unsecured Notes $ — $ — $ — $ 14 $ 13 $ 1 2024 Senior Unsecured Notes 122 123 (1 ) 46 42 4 2025 Senior Unsecured Notes 38 35 3 330 300 30 Total $ 160 $ 158 $ 2 $ 390 $ 355 $ 35 |
First Lien Term Loans | First Lien Term Loans Our First Lien Term Loans are summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates (1) 2019 2018 2019 2018 2019 First Lien Term Loan $ — $ 389 — % 4.9 % 2023 First Lien Term Loans — 1,059 — 5.4 2024 First Lien Term Loan (2) 1,514 1,528 5.3 5.0 2026 First Lien Term Loans 1,653 — 5.4 — Total First Lien Term Loans $ 3,167 $ 2,976 ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. (2) Our 2024 First Lien Term Loan, which matures on January 15, 2024, carries substantially similar terms as our $950 million first lien senior secured term loan as discussed below. |
First Lien Notes | First Lien Notes Our First Lien Notes are summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average (1) 2019 2018 2019 2018 2022 First Lien Notes (2) $ 245 $ 743 6.4 % 6.4 % 2024 First Lien Notes (3) 184 486 6.1 6.1 2026 First Lien Notes 1,172 1,171 5.5 5.5 2028 First Lien Notes (2)(3) 1,234 — 4.7 — Total First Lien Notes $ 2,835 $ 2,400 ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. (2) On December 20, 2019, we used the proceeds from the issuance of our 2028 First Lien Notes (discussed below) to redeem approximately $505 million in aggregate principal amount of our 2022 First Lien Notes, plus accrued and unpaid interest. On January 21, 2020, we redeemed the remaining $245 million in aggregate principal amount of our 2022 First Lien Notes, which was included in debt, current portion on our Consolidated Balance Sheet at December 31, 2019, with the proceeds from the 2028 First Lien Notes, which was included in cash and cash equivalents on our Consolidated Balance Sheet at December 31, 2019 . We recorded approximately $6 million in loss on extinguishment of debt which is comprised of approximately $1 million of prepayment premiums and approximately $5 million associated with the write-off of unamortized discount and debt issuance costs during the fourth quarter of 2019 associated with the redemption. (3) On December 20, 2019, we used the proceeds from the issuance of our 2028 First Lien Notes (discussed below) to redeem approximately $306 million of the total aggregate debt amount of 2024 First Lien Notes, plus accrued and unpaid interest. On January 21, 2020, we redeemed the remaining $184 million in aggregate principal amount of our 2024 First Lien Notes, which was included in debt, current portion on our Consolidated Balance Sheet at December 31, 2019, with the proceeds from the 2028 First Lien Notes which was included in cash and cash equivalents on our Consolidated Balance Sheet at December 31, 2019 . We recorded approximately $14 million in loss on extinguishment of debt which is comprised of approximately $11 million of prepayment premiums and approximately $3 million associated with the write-off of unamortized debt issuance costs during the fourth quarter of 2019 associated with the redemption. |
Project Financing Notes Payable and Other | The components of our project financing, notes payable and other are (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates (1) 2019 2018 2019 2018 Russell City due 2023 $ 272 $ 341 6.6 % 6.5 % Steamboat due 2025 351 384 4.6 4.5 OMEC due 2024 (2) — 218 — 7.1 Los Esteros due 2023 135 163 5.2 4.7 Pasadena (3) 62 76 8.9 8.9 Bethpage Energy Center 3 due 2020-2025 (4) 45 53 7.0 7.1 Other 14 29 — — Total $ 879 $ 1,264 _____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. (2) On August 14, 2019, we repaid the project debt associated with OMEC from a portion of the proceeds received from the issuance of our 2026 First Lien Term Loans (as discussed above), together with cash on hand. (3) Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP. (4) Represents a weighted average of first and second lien loans for the weighted average effective interest rates. |
CCFC Term Loans | CCFC Term Loan Our CCFC Term Loan is summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates (1) 2019 2018 2019 2018 CCFC Term Loan $ 967 $ 974 5.2 % 4.9 % ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. |
Schedule of Line of Credit Facilities | Corporate Revolving Facility and Other Letters of Credit Facilities The table below represents amounts issued under our letter of credit facilities at December 31, 2019 and 2018 (in millions): 2019 2018 Corporate Revolving Facility $ 604 $ 693 CDHI 3 251 Various project financing facilities 184 228 Other corporate facilities 294 193 Total $ 1,085 $ 1,365 |
Fair Value, by Balance Sheet Grouping | The following table details the fair values and carrying values of our debt instruments at December 31, 2019 and 2018 (in millions): 2019 2018 Fair Value Carrying Fair Value Carrying Value Senior Unsecured Notes $ 3,764 $ 3,663 $ 2,803 $ 3,036 First Lien Term Loans 3,238 3,167 2,877 2,976 First Lien Notes 2,929 2,835 2,299 2,400 Project financing, notes payable and other (1) 822 817 1,209 1,188 CCFC Term Loan 982 967 938 974 Revolving facilities 122 122 30 30 Total $ 11,857 $ 11,571 $ 10,156 $ 10,604 ____________ (1) Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP. |
Assets and Liabilities with R_2
Assets and Liabilities with Recurring Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |
Fair Value, Measurement Inputs, Disclosure | The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 and 2018 , by level within the fair value hierarchy: Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2019 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 784 $ — $ — $ 784 Commodity instruments: Commodity exchange traded derivatives contracts 872 — — 872 Commodity forward contracts (2) — 245 294 539 Interest rate hedging instruments — 12 — 12 Effect of netting and allocation of collateral (3)(4) (872 ) (131 ) (18 ) (1,021 ) Total assets $ 784 $ 126 $ 276 $ 1,186 Liabilities: Commodity instruments: Commodity exchange traded derivatives contracts 984 — — 984 Commodity forward contracts (2) — 285 123 408 Interest rate hedging instruments — 31 — 31 Effect of netting and allocation of collateral (3)(4) (984 ) (133 ) (18 ) (1,135 ) Total liabilities $ — $ 183 $ 105 $ 288 Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2018 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 168 $ — $ — $ 168 Commodity instruments: Commodity exchange traded derivatives contracts 933 — — 933 Commodity forward contracts (2) — 338 212 550 Interest rate hedging instruments — 40 — 40 Effect of netting and allocation of collateral (3)(4) (933 ) (262 ) (26 ) (1,221 ) Total assets $ 168 $ 116 $ 186 $ 470 Liabilities: Commodity instruments: Commodity exchange traded derivatives contracts 932 — — 932 Commodity forward contracts (2) — 549 220 769 Interest rate hedging instruments — 10 — 10 Effect of netting and allocation of collateral (3)(4) (932 ) (310 ) (26 ) (1,268 ) Total liabilities $ — $ 249 $ 194 $ 443 ___________ (1) As of December 31, 2019 and 2018 , we had cash equivalents of $573 million and $23 million included in cash and cash equivalents and $211 million and $145 million included in restricted cash, respectively. (2) Includes OTC swaps and options. (3) We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 10 for further discussion of our derivative instruments subject to master netting arrangements. (4) Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $112 million , $2 million and nil , respectively, at December 31, 2019 . Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $(1) million , $48 million and nil , respectively, at December 31, 2018 . |
Fair Value Inputs, Assets, Quantitative Information | The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at December 31, 2019 and 2018 : Quantitative Information about Level 3 Fair Value Measurements December 31, 2019 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts (1) $ 158 Discounted cash flow Market price (per MWh) $4.85 — $184.15/MWh Power Congestion Products $ 17 Discounted cash flow Market price (per MWh) $(10.32)— $20.00/MWh Natural Gas Contracts $ (20 ) Discounted cash flow Market price (per MMBtu) $1.73 — $6.45/MMBtu Quantitative Information about Level 3 Fair Value Measurements December 31, 2018 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts (1) $ 36 Discounted cash flow Market price (per MWh) $2.12 — $227.98/MWh Power Congestion Products $ 26 Discounted cash flow Market price (per MWh) $(11.71) — $11.88/MWh Natural Gas Contracts $ (73 ) Discounted cash flow Market price (per MMBtu) $0.75 — $8.87/MMBtu ___________ (1) Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy. |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation | The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the years ended December 31, 2019 , 2018 and 2017 (in millions): 2019 2018 2017 Balance, beginning of period $ (8 ) $ 197 $ 416 Realized and mark-to-market gains (losses): Included in net income (loss): Included in operating revenues (1) 171 (88 ) 32 Included in fuel and purchased energy expense (2) (21 ) (45 ) 50 Change in collateral — — (17 ) Purchases, issuances and settlements: Purchases 5 18 4 Issuances (3 ) (2 ) (1 ) Settlements 56 (86 ) (179 ) Transfers in and/or out of level 3 (3) : Transfers into level 3 (4) 1 — (2 ) Transfers out of level 3 (5) (30 ) (2 ) (106 ) Balance, end of period $ 171 $ (8 ) $ 197 Change in unrealized gains (losses) relating to instruments still held at end of period $ 150 $ (133 ) $ 82 ___________ (1) For power contracts and other power-related products, included on our Consolidated Statements of Operations. (2) For natural gas and power contracts, swaps and options, included on our Consolidated Statements of Operations. (3) We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 during the years ended December 31, 2019 , 2018 and 2017 . (4) We had $1 million in gains, nil and $(2) million in losses transferred out of level 2 into level 3 for the years ended December 31, 2019 , 2018 and 2017 , respectively. (5) We had $30 million , $2 million and $104 million in gains transferred out of level 3 into level 2 during the years ended December 31, 2019 , 2018 and 2017 , respectively, due to changes in market liquidity in various power markets and $2 million in gains transferred out of level 3 during the years ended December 31, 2017, to other assets following the election of the normal purchase normal sales exemption and the discontinuance of derivative accounting treatment as of the date of this election for certain commodity contracts. |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | As of December 31, 2019 and 2018 , the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions): Derivative Instruments Notional Amounts 2019 2018 Unit of Measure Power (MWh) (184 ) (161 ) Million MWh Natural gas (MMBtu) 1,063 1,045 Million MMBtu Environmental credits (Tonnes) 26 13 Million Tonnes Interest rate hedging instruments $ 4.8 $ 4.5 Billion U.S. dollars |
Offsetting Assets | The following tables present the fair values of our derivative instruments and our net exposure after offsetting amounts subject to a master netting arrangement with the same counterparty to our derivative instruments recorded on our Consolidated Balance Sheets by location and hedge type at December 31, 2019 and 2018 (in millions): December 31, 2019 Gross Amounts of Assets and (Liabilities) Gross Amounts Offset on the Consolidated Balance Sheets Net Amount Presented on the Consolidated Balance Sheets (1) Derivative assets: Commodity exchange traded derivatives contracts $ 727 $ (727 ) $ — Commodity forward contracts 262 (108 ) 154 Interest rate hedging instruments 2 — 2 Total current derivative assets (2) $ 991 $ (835 ) $ 156 Commodity exchange traded derivatives contracts 145 (145 ) — Commodity forward contracts 277 (41 ) 236 Interest rate hedging instruments 10 — 10 Total long-term derivative assets (2) $ 432 $ (186 ) $ 246 Total derivative assets $ 1,423 $ (1,021 ) $ 402 Derivative (liabilities): Commodity exchange traded derivatives contracts $ (830 ) $ 830 $ — Commodity forward contracts (321 ) 109 (212 ) Interest rate hedging instruments (13 ) — (13 ) Total current derivative (liabilities) (2) $ (1,164 ) $ 939 $ (225 ) Commodity exchange traded derivatives contracts (154 ) 154 — Commodity forward contracts (87 ) 42 (45 ) Interest rate hedging instruments (18 ) — (18 ) Total long-term derivative (liabilities) (2) $ (259 ) $ 196 $ (63 ) Total derivative liabilities $ (1,423 ) $ 1,135 $ (288 ) Net derivative assets (liabilities) $ — $ 114 $ 114 December 31, 2018 Gross Amounts of Assets and (Liabilities) Gross Amounts Offset on the Consolidated Balance Sheets Net Amount Presented on the Consolidated Balance Sheets (1) Derivative assets: Commodity exchange traded derivatives contracts $ 820 $ (820 ) $ — Commodity forward contracts 341 (229 ) 112 Interest rate hedging instruments 30 — 30 Total current derivative assets (3) $ 1,191 $ (1,049 ) $ 142 Commodity exchange traded derivatives contracts 113 (113 ) — Commodity forward contracts 209 (59 ) 150 Interest rate hedging instruments 10 — 10 Total long-term derivative assets (3) $ 332 $ (172 ) $ 160 Total derivative assets $ 1,523 $ (1,221 ) $ 302 Derivative (liabilities): Commodity exchange traded derivatives contracts $ (764 ) $ 764 $ — Commodity forward contracts (576 ) 277 (299 ) Interest rate hedging instruments (4 ) — (4 ) Total current derivative (liabilities) (3) $ (1,344 ) $ 1,041 $ (303 ) Commodity exchange traded derivatives contracts (168 ) 168 — Commodity forward contracts (193 ) 59 (134 ) Interest rate hedging instruments (6 ) — (6 ) Total long-term derivative (liabilities) (3) $ (367 ) $ 227 $ (140 ) Total derivative liabilities $ (1,711 ) $ 1,268 $ (443 ) Net derivative assets (liabilities) $ (188 ) $ 47 $ (141 ) ____________ (1) At December 31, 2019 and 2018 , we had $191 million and $244 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Balance Sheets primarily related to initial margin requirements. (2) At December 31, 2019 , current and long-term derivative assets are shown net of collateral of $(4) million and $(4) million , respectively, and current and long-term derivative liabilities are shown net of collateral of $108 million and $14 million , respectively. (3) At December 31, 2018 , current and long-term derivative assets are shown net of collateral of $(58) million and $(8) million , respectively, and current and long-term derivative liabilities are shown net of collateral of $49 million and $64 million , respectively. |
Derivative Instrument by Accounting Designation | December 31, 2019 December 31, 2018 Fair Value of Derivative Assets Fair Value of Derivative Liabilities Fair Value of Derivative Assets Fair Value of Derivative Liabilities Derivatives designated as cash flow hedging instruments: Interest rate hedging instruments $ 12 $ 29 $ 40 $ 10 Total derivatives designated as cash flow hedging instruments $ 12 $ 29 $ 40 $ 10 Derivatives not designated as hedging instruments: Commodity instruments $ 390 $ 257 $ 262 $ 433 Interest rate hedging instruments — 2 — — Total derivatives not designated as hedging instruments $ 390 $ 259 $ 262 $ 433 Total derivatives $ 402 $ 288 $ 302 $ 443 |
Realized Unrealized Gain Loss by Instrument | The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Statements of Operations for the years ended December 31, 2019 , 2018 and 2017 (in millions): 2019 2018 2017 Realized gain (loss) (1)(2) Commodity derivative instruments $ 256 $ 193 $ 7 Total realized gain $ 256 $ 193 $ 7 Mark-to-market gain (loss) (3) Commodity derivative instruments $ 278 $ (208 ) $ (171 ) Interest rate hedging instruments (3 ) 3 2 Total mark-to-market gain (loss) $ 275 $ (205 ) $ (169 ) Total activity, net $ 531 $ (12 ) $ (162 ) ___________ (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. (2) Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions. (3) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure. |
Derivatives Not Designated as Hedging Instruments [Table Text Block] | 2019 2018 2017 Realized and mark-to-market gain (loss) (1) Derivatives contracts included in operating revenues (2)(3) $ 816 $ (369 ) $ (69 ) Derivatives contracts included in fuel and purchased energy expense (2)(3) (282 ) 354 (95 ) Interest rate hedging instruments included in interest expense (3 ) 3 2 Total activity, net $ 531 $ (12 ) $ (162 ) ___________ (1) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure. (2) Does not include the realized value associated with derivative instruments that settle through physical delivery. (3) Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions |
Derivatives Designated as Hedges | The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the years ended December 31, 2019 , 2018 and 2017 (in millions): Gain (Loss) Recognized in OCI (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) (3)(4) 2019 2018 2017 2019 2018 2017 Affected Line Item on the Consolidated Statements of Operations Interest rate hedging instruments (1)(2) $ (41 ) $ 45 $ 21 $ (1 ) $ (5 ) $ (43 ) Interest expense Interest rate hedging instruments (1)(2) 1 1 5 (1 ) (1 ) (5 ) Depreciation expense Total $ (40 ) $ 46 $ 26 $ (2 ) $ (6 ) $ (48 ) ____________ (1) We recorded a gain of $1 million on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the years ended December 31, 2018 and 2017. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings. (2) We recorded an income tax benefit of $2 million and income tax expense of $5 million and $6 million for the years ended December 31, 2019 , 2018 and 2017 , respectively, in AOCI related to our cash flow hedging activities. (3) Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $72 million , $34 million and $72 million at December 31, 2019 , 2018 and 2017 , respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million , $ 3 million and $ 6 million at December 31, 2019 , 2018 and 2017 , respectively. (4) Includes losses of $2 million , $1 million and nil that were reclassified from AOCI to interest expense for the years ended December 31, 2019 , 2018 and 2017 , respectively, where the hedged transactions became probable of not occurring. |
Use of Collateral (Tables)
Use of Collateral (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Use of Collateral [Abstract] | |
Schedule of Collateral | The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of December 31, 2019 and 2018 (in millions): 2019 2018 Margin deposits (1) $ 432 $ 343 Natural gas and power prepayments 29 31 Total margin deposits and natural gas and power prepayments with our counterparties (2) $ 461 $ 374 Letters of credit issued $ 906 $ 1,166 First priority liens under power and natural gas agreements 42 92 First priority liens under interest rate hedging instruments 31 10 Total letters of credit and first priority liens with our counterparties $ 979 $ 1,268 Margin deposits posted with us by our counterparties (1)(3) $ 127 $ 52 Letters of credit posted with us by our counterparties 25 27 Total margin deposits and letters of credit posted with us by our counterparties $ 152 $ 79 ___________ (1) We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 10 for further discussion of our derivative instruments subject to master netting arrangements. (2) At December 31, 2019 and 2018 , $117 million and $79 million , respectively, were included in current and long-term derivative assets and liabilities, $336 million and $286 million , respectively, were included in margin deposits and other prepaid expense and $8 million and $9 million , respectively, were included in other assets on our Consolidated Balance Sheets. (3) At December 31, 2019 and 2018 , $3 million and $32 million , respectively, were included in current and long-term derivative assets and liabilities, $93 million and $20 million , respectively, were included in other current liabilities and $31 million and nil , respectively, were included in other long-term liabilities on our Consolidated Balance Sheets. |
Income Taxes Income Taxes (Tabl
Income Taxes Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Schedule of Income before Income Tax, Domestic and Foreign | The jurisdictional components of income from continuing operations before income tax expense (benefit), attributable to Calpine, for the years ended December 31, 2019 , 2018 and 2017 , are as follows (in millions): 2019 2018 2017 U.S. $ 836 $ 47 $ (358 ) International 32 27 27 Total $ 868 $ 74 $ (331 ) |
Schedule of Components of Income Tax Expense (Benefit) | The components of income tax expense from continuing operations for the years ended December 31, 2019 , 2018 and 2017 , consisted of the following (in millions): 2019 2018 2017 Current: Federal $ (2 ) $ — $ (10 ) State 2 20 18 Foreign 3 (3 ) (14 ) Total current 3 17 (6 ) Deferred: Federal 66 (1 ) 5 State 28 (6 ) 6 Foreign 1 54 3 Total deferred 95 47 14 Total income tax expense $ 98 $ 64 $ 8 |
Schedule of Effective Income Tax Rate Reconciliation | A reconciliation of the federal statutory rate of 21% and, prior to 2018, 35% to our effective rate from continuing operations for the years ended December 31, 2019 , 2018 and 2017 , is as follows: 2019 2018 2017 Federal statutory tax rate 21.0 % 21.0 % 35.0 % State tax expense, net of federal benefit 2.8 17.0 (6.0 ) Change in tax rate of net deferred tax asset — — (168.8 ) Valuation allowances offsetting tax rate change — — 168.8 Valuation allowances against future tax benefits (11.2 ) (31.7 ) (33.0 ) Valuation allowance related to foreign taxes — (138.3 ) 0.5 Decrease in foreign NOL due to change in ownership — 202.3 — Distributions from foreign affiliates and foreign taxes 0.2 6.6 (2.0 ) Change in unrecognized tax benefits — (8.0 ) 5.1 Disallowed compensation — 7.7 (0.6 ) Stock-based compensation — (1.5 ) (0.9 ) Equity earnings 0.1 1.4 (0.8 ) Merger Related Fees/Expenses — 12.7 — Depletion in excess of basis (0.3 ) (4.0 ) — Other differences (1.3 ) 1.3 0.3 Effective income tax rate 11.3 % 86.5 % (2.4 )% |
Schedule of Deferred Tax Assets and Liabilities | The components of deferred income taxes as of December 31, 2019 and 2018 , are as follows (in millions): 2019 2018 Deferred tax assets: NOL and credit carryforwards $ 1,731 $ 1,595 Taxes related to risk management activities and derivatives 18 7 Reorganization items and impairments 73 166 Other differences 62 101 Deferred tax assets before valuation allowance 1,884 1,869 Valuation allowance (873 ) (1,000 ) Total deferred tax assets 1,011 869 Deferred tax liabilities: Property, plant and equipment (1,125 ) (890 ) Total deferred tax liabilities (1,125 ) (890 ) Net deferred tax asset (liability) (114 ) (21 ) Less: Non-current deferred tax liability (116 ) (22 ) Deferred income tax asset, non-current $ 2 $ 1 |
Schedule of Income Tax Contingencies | A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2019 , 2018 and 2017 , is as follows (in millions): 2019 2018 2017 Balance, beginning of period $ (28 ) $ (38 ) $ (59 ) Increases related to prior year tax positions — (7 ) — Decreases related to prior year tax positions — 17 11 Increases related to current year tax positions (1 ) — (2 ) Decreases related to change in tax rate of net deferred tax asset — — 12 Balance, end of period $ (29 ) $ (28 ) $ (38 ) |
Capital Structure (Tables)
Capital Structure (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Capital Structure [Abstract] | |
Schedule of Common Stock Activity | The table below summarizes our common stock activity for the years ended December 31, 2019 , 2018 and 2017 . Shares Issued Shares Held in Treasury Shares Outstanding Balance, December 31, 2016 359,627,113 (565,349 ) 359,061,764 Shares issued under Calpine Equity Incentive Plans 2,050,778 (596,451 ) 1,454,327 Balance, December 31, 2017 361,677,891 (1,161,800 ) 360,516,091 Shares issued under Calpine Equity Incentive Plans 355,805 (477,711 ) (121,906 ) Cancellation of Calpine Corporation common stock in accordance with the Merger Agreement (362,033,696 ) 1,639,511 (360,394,185 ) Conversion of Merger Sub common stock to Calpine Corporation common stock in accordance with the Merger Agreement 105.2 — 105.2 Balance, December 31, 2018 105.2 — 105.2 Shares issued under Calpine Equity Incentive Plans — — — Balance, December 31, 2019 105.2 — 105.2 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule Of Future Minimum Payments For Commodities | At December 31, 2019 , we had future commitments for the purchase, transportation, or storage of commodities as detailed below (in millions): 2020 $ 402 2021 178 2022 121 2023 98 2024 41 Thereafter 103 Total $ 943 |
Schedule of Guarantor Obligations | At December 31, 2019 , guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and the guarantee under our Account Receivable Sales Program and their respective expiration dates were as follows (in millions): Guarantee Commitments 2020 2021 2022 2023 2024 Thereafter Total Guarantee of subsidiary obligations (1) $ 30 $ 29 $ 24 $ 14 $ 13 $ 39 $ 149 Standby letters of credit (2)(3)(4) 1,015 32 — 38 — — 1,085 Surety bonds (4)(5)(6) 10 7 — — — 94 111 Guarantee under Accounts Receivable Sales Program (7) 222 — — — — — 222 Total $ 1,277 $ 68 $ 24 $ 52 $ 13 $ 133 $ 1,567 ____________ (1) Represents Calpine Corporation guarantees of certain power plant leases and related interest. All guaranteed finance leases are recorded on our Consolidated Balance Sheets. (2) The standby letters of credit disclosed above represent those disclosed in Note 8. (3) Letters of credit are renewed annually and as such all amounts are reflected in the year of letter of credit expiration. The related commercial obligations extend for multiple years, therefore, renewal of the letter of credit will likely follow the term of the associated commercial obligation. (4) These are contingent off balance sheet obligations. (5) The majority of surety bonds do not have expiration or cancellation dates. (6) As of December 31, 2019 , no cash collateral is outstanding related to these bonds. (7) Calpine has guaranteed the performance of Calpine Solutions under the Accounts Receivable Sales Program. The Accounts Receivable Sales Program expires on November 27, 2020 . |
Segment and Significant Custo_2
Segment and Significant Customer Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Segment and Significant Customer Information [Abstract] | |
Schedule of Financial Data for Segments | The tables below show our financial data for our segments (including a reconciliation of our Commodity Margin to income (loss) from operations by segment) for the periods indicated (in millions). Year Ended December 31, 2019 Wholesale West Texas East Retail Consolidation and Elimination Total Total operating revenues (1) $ 2,743 $ 3,081 $ 2,164 $ 4,093 $ (2,009 ) $ 10,072 Commodity Margin $ 1,151 $ 857 $ 924 $ 382 $ — $ 3,314 Add: Mark-to-market commodity activity, net and other (2) 219 154 46 (131 ) (34 ) 254 Less: Operating and maintenance expense 340 269 278 148 (34 ) 1,001 Depreciation and amortization expense 254 196 191 53 — 694 General and other administrative expense 35 53 45 17 — 150 Other operating expenses 31 6 42 — — 79 Impairment losses — 13 71 — — 84 (Gain) on sale of assets, net (4 ) — (6 ) — — (10 ) (Income) from unconsolidated subsidiaries — — (24 ) 2 — (22 ) Income from operations 714 474 373 31 — 1,592 Interest expense 609 (Gain) loss on extinguishment of debt and other (income) expense, net 95 Income before income taxes $ 888 Year Ended December 31, 2018 Wholesale West Texas East Retail Consolidation and Elimination Total Total operating revenues (1) $ 1,988 $ 2,860 $ 1,987 $ 3,976 $ (1,299 ) $ 9,512 Commodity Margin $ 1,060 $ 646 $ 970 $ 357 $ — $ 3,033 Add: Mark-to-market commodity activity, net and other (2) (165 ) (197 ) 40 84 (32 ) (270 ) Less: Operating and maintenance expense 348 272 269 163 (32 ) 1,020 Depreciation and amortization expense 269 237 180 53 — 739 General and other administrative expense 40 61 38 19 — 158 Other operating expenses 42 24 32 — — 98 Impairment losses — — 10 — — 10 (Income) from unconsolidated subsidiaries — — (26 ) 2 — (24 ) Income (loss) from operations 196 (145 ) 507 204 — 762 Interest expense 617 (Gain) loss on extinguishment of debt and other (income) expense, net 53 Income before income taxes $ 92 Year Ended December 31, 2017 Wholesale West Texas East Retail Consolidation and Elimination Total Total operating revenues (1) $ 1,881 $ 2,342 $ 1,658 $ 3,797 $ (926 ) $ 8,752 Commodity Margin $ 970 $ 552 $ 790 $ 396 $ — $ 2,708 Add: Mark-to-market commodity activity, net and other (2) (19 ) (174 ) (62 ) (10 ) (29 ) (294 ) Less: Operating and maintenance expense 361 308 302 138 (29 ) 1,080 Depreciation and amortization expense 240 208 201 75 — 724 General and other administrative expense 45 66 27 17 — 155 Other operating expenses 38 14 33 — — 85 Impairment losses 28 13 — — — 41 (Gain) on sale of assets, net — — (27 ) — — (27 ) (Income) from unconsolidated subsidiaries — — (24 ) 2 — (22 ) Income (loss) from operations 239 (231 ) 216 154 — 378 Interest expense 621 Debt modification and extinguishment costs and other (income) expense, net 70 Loss before income taxes $ (313 ) __________ (1) Includes intersegment revenues of $530 million , $488 million and $324 million in the West, $946 million , $573 million and $361 million in Texas, $522 million , $234 million and $237 million in the East and $11 million , $4 million , $4 million in Retail for the years ended December 31, 2019 , 2018 and 2017 , respectively. (2) Includes $1 million , nil and $(8) million of lease levelization and $78 million , $104 million and $178 million of amortization expense for the years ended December 31, 2019 , 2018 and 2017 , respectively. |
Quarterly Consolidated Financ_2
Quarterly Consolidated Financial Data (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Consolidated Financial Data (unaudited) | Quarter Ended December 31 September 30 June 30 March 31 (in millions) 2019 Operating revenues $ 2,082 $ 2,792 $ 2,599 $ 2,599 Income from operations $ 108 $ 682 $ 444 $ 358 Net income (loss) attributable to Calpine $ (156 ) $ 485 $ 266 $ 175 2018 Operating revenues $ 2,354 $ 2,890 $ 2,259 $ 2,009 Income (loss) from operations $ 105 $ 568 $ 417 $ (328 ) Net income (loss) attributable to Calpine $ (16 ) $ 272 $ 352 $ (598 ) |
Organization and Operations Org
Organization and Operations Organization and Operations (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 08, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||
Sale of Stock, Price Per Share | $ 15.25 | ||||
Sale of Stock, Consideration Received on Transaction | $ 5,600 | ||||
Payments for Merger Related Costs | $ 0 | $ 33 | $ 15 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Current | $ 299 | $ 167 | ||
Non-current | 46 | 34 | ||
Total | 345 | 201 | ||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Gain on Business Interruption Insurance Recovery | $ 11 | 14 | $ 27 | |
Income Taxes Threshold Percentage | 50.00% | |||
Property, plant and equipment, salvage value (as a percent) | 10.00% | |||
Goodwill | $ 242 | 242 | ||
Impairment losses | 84 | 10 | 41 | |
Asset retirement obligations | 68 | 63 | ||
Long-term Debt | 11,857 | 10,156 | ||
Property, Plant and Equipment, Net | $ 11,963 | 12,442 | ||
Freestone Energy Center [Member] | ||||
Jointly Owned Plants [Abstract] | ||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 75.00% | |||
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service | $ 379 | |||
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation | (177) | |||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | $ 0 | |||
Hidalgo Energy Center [Member] | ||||
Jointly Owned Plants [Abstract] | ||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 78.50% | |||
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service | $ 250 | |||
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation | (113) | |||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | 0 | |||
Debt Service | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Current | 58 | 13 | ||
Non-current | 8 | 8 | ||
Total | 66 | 21 | ||
Construction Major Maintenance | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Current | 28 | 23 | ||
Non-current | 6 | 24 | ||
Total | 34 | 47 | ||
Security Project Insurance | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Current | 209 | 120 | ||
Non-current | 31 | 0 | ||
Total | 240 | 120 | ||
Other | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Current | 4 | 11 | ||
Non-current | 1 | 2 | ||
Total | $ 5 | 13 | ||
Greenfield [Member] | ||||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Ownership percentage in equity method investment | [1] | 50.00% | ||
Whitby [Member] | ||||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Ownership percentage in equity method investment | [2] | 0.00% | ||
Calpine Receivables [Member] | ||||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Ownership percentage in equity method investment | 100.00% | |||
West [Member] | ||||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Impairment losses | $ 0 | 0 | 28 | |
Texas [Member] | ||||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Impairment losses | 13 | 0 | 13 | |
East [Member] | ||||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Impairment losses | 71 | $ 10 | $ 0 | |
Russell City Energy [Member] | ||||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Long-term Debt | 272 | |||
Property, Plant and Equipment, Net | 647 | |||
Los Esteros Project [Member] | ||||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Long-term Debt | 135 | |||
Property, Plant and Equipment, Net | 427 | |||
Minimum [Member] | ||||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $ 191 | |||
[1] | Includes our share of accumulated other comprehensive income/loss related to interest rate hedging instruments associated with our unconsolidated subsidiary Greenfield LP’s debt. | |||
[2] | On November 20, 2019, we sold our 50% interest in Whitby to a third party and recorded a gain on sale of assets, net of approximately $5 million. |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies Intangible Assets by Component (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Assets, Gross | $ 933 | $ 1,031 | |
Finite-Lived Intangible Assets, Accumulated Amortization | 593 | 619 | |
Finite-Lived Intangible Assets, Net | 340 | 412 | |
Amortization of Intangible Assets | 72 | 100 | $ 175 |
Acquired contracts [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Assets, Gross | $ 444 | 458 | |
Acquired contracts [Member] | Minimum [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Asset, Useful Life | 0 years | ||
Acquired contracts [Member] | Maximum [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Asset, Useful Life | 9 years | ||
Customer Relationships [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Assets, Gross | $ 445 | 445 | |
Customer Relationships [Member] | Minimum [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Asset, Useful Life | 7 years | ||
Customer Relationships [Member] | Maximum [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Asset, Useful Life | 14 years | ||
Trademarks and Trade Names [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Assets, Gross | $ 40 | 40 | |
Trademarks and Trade Names [Member] | Minimum [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Asset, Useful Life | 15 years | ||
Trademarks and Trade Names [Member] | Maximum [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Asset, Useful Life | 15 years | ||
Other Intangible Assets [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Assets, Gross | $ 4 | $ 88 | |
Other Intangible Assets [Member] | Minimum [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Asset, Useful Life | 39 years | ||
Other Intangible Assets [Member] | Maximum [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Asset, Useful Life | 44 years |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies Amortization of Intangible Assets for Future Years (Details) $ in Millions | Dec. 31, 2019USD ($) |
Schedule of Finite Lived Assets Future Amortization Expense [Abstract] | |
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | $ 44 |
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 39 |
Finite-Lived Intangible Assets, Amortization Expense, Year Three | 36 |
Finite-Lived Intangible Assets, Amortization Expense, Year Four | 28 |
Finite-Lived Intangible Assets, Amortization Expense, Year Five | $ 28 |
Revenue from Contracts with C_3
Revenue from Contracts with Customers Disaggregation of Revenues (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 9,437 | $ 9,865 | $ 8,836 | ||||||||||||
Revenues | $ 2,082 | $ 2,792 | $ 2,599 | $ 2,599 | $ 2,354 | $ 2,890 | $ 2,259 | $ 2,009 | 10,072 | [1] | 9,512 | [1] | 8,752 | [1] | |
Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 4,657 | 5,048 | |||||||||||||
Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 845 | 903 | |||||||||||||
Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 5,502 | 5,951 | |||||||||||||
Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | 0 | 0 | ||||||||||||
Revenues Relating to Leases and Derivative Instruments [Member] | |||||||||||||||
Revenues | [3] | 4,570 | 3,561 | ||||||||||||
West [Member] | |||||||||||||||
Revenues | [1] | 2,743 | 1,988 | 1,881 | |||||||||||
West [Member] | Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 948 | 1,070 | |||||||||||||
West [Member] | Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 173 | 152 | |||||||||||||
West [Member] | Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,121 | 1,222 | |||||||||||||
West [Member] | Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | 44 | 30 | ||||||||||||
Texas [Member] | |||||||||||||||
Revenues | [1] | 3,081 | 2,860 | 2,342 | |||||||||||
Texas [Member] | Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,406 | 1,500 | |||||||||||||
Texas [Member] | Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 125 | 94 | |||||||||||||
Texas [Member] | Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,531 | 1,594 | |||||||||||||
Texas [Member] | Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | 55 | 34 | ||||||||||||
East [Member] | |||||||||||||||
Revenues | [1] | 2,164 | 1,987 | 1,658 | |||||||||||
East [Member] | Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 609 | 621 | |||||||||||||
East [Member] | Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 547 | 657 | |||||||||||||
East [Member] | Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,156 | 1,278 | |||||||||||||
East [Member] | Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | 99 | 89 | ||||||||||||
Retail [Member] | |||||||||||||||
Revenues | [1] | 4,093 | 3,976 | $ 3,797 | |||||||||||
Retail [Member] | Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,694 | 1,857 | |||||||||||||
Retail [Member] | Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||||||||||||
Retail [Member] | Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,694 | 1,857 | |||||||||||||
Retail [Member] | Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | 9 | 4 | ||||||||||||
Intersegment Eliminations [Member] | Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||||||||||||
Intersegment Eliminations [Member] | Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||||||||||||
Intersegment Eliminations [Member] | Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||||||||||||
Intersegment Eliminations [Member] | Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | $ (207) | $ (157) | ||||||||||||
[1] | Includes intersegment revenues of $530 million, $488 million and $324 million in the West, $946 million, $573 million and $361 million in Texas, $522 million, $234 million and $237 million in the East and $11 million, $4 million, $4 million in Retail for the years ended December 31, 2019, 2018 and 2017, respectively. | ||||||||||||||
[2] | Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine. | ||||||||||||||
[3] | Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Statements of Operations. |
Revenue from Contracts with C_4
Revenue from Contracts with Customers Performance Obligations and Contract Balances (Details) - Environmental Credits [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Deferred Revenue, Current | $ 14 | $ 14 |
Contract with Customer, Liability, Revenue Recognized | $ 14 | $ 15 |
Revenue from Contracts with C_5
Revenue from Contracts with Customers Performance Obligations Not Yet Satisfied (Details) - Capacity Revenue [Member] $ in Millions | Dec. 31, 2019USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 639 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 633 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 408 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 141 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 49 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 63 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period |
Leases (Details)
Leases (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Operating Leases, Rent Expense, Net | $ 53 | $ 50 | ||
Capital Leased Assets, Gross | 715 | |||
Less: Accumulated depreciation | $ 6,851 | 6,832 | ||
Operating Lease, Lease Income | [1] | $ 341 | ||
Lessee, Finance Lease, Term of Contract | 30 years | |||
Assets Held under Capital Leases [Member] | ||||
Less: Accumulated depreciation | $ 353 | |||
[1] | Revenues associated with our operating leases are included in Commodity revenue and other revenue on our Consolidated Statement of Operations. |
Leases Components of operating
Leases Components of operating and finance lease expense (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Component of operating and finance lease expense [Abstract] | |
Operating Lease, Cost | $ 46 |
Finance Lease, Right-of-Use Asset, Amortization | 8 |
Finance Lease, Interest Expense | 8 |
Finance lease, expense, Total | 16 |
Variable Lease, Cost | 9 |
Lease, Cost | $ 71 |
Leases Future Minimum Lease Pay
Leases Future Minimum Lease Payments (Details) $ in Millions | Dec. 31, 2019USD ($) | |
Operating and Finance Leases [Abstract] | ||
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year | $ 21 | [1] |
Finance Lease, Liability, Payments, Remainder of Fiscal Year | 16 | [2] |
Lessee, Operating Lease, Liability, Payments, Due Year Two | 22 | [1] |
Finance Lease, Liability, Payments, Due Year Two | 16 | [2] |
Lessee, Operating Lease, Liability, Payments, Due Year Three | 20 | [1] |
Finance Lease, Liability, Payments, Due Year Three | 15 | [2] |
Lessee, Operating Lease, Liability, Payments, Due Year Four | 19 | [1] |
Finance Lease, Liability, Payments, Due Year Four | 19 | [2] |
Lessee, Operating Lease, Liability, Payments, Due Year Five | 18 | [1] |
Finance Lease, Liability, Payments, Due Year Five | 8 | [2] |
Lessee, Operating Lease, Liability, Payments, Due after Year Five | 185 | [1] |
Finance Lease, Liability, Payments, Due after Year Five | 26 | [2] |
Lessee, Operating Lease, Liability, Payments, Due | 285 | [1] |
Finance Lease, Liability, Payment, Due | 100 | [2] |
Lessee, Operating Lease, Liability, Undiscounted Excess Amount | 103 | [1] |
Finance Lease, Liability, Undiscounted Excess Amount | 27 | [2] |
Operating Lease, Liability | 182 | [1] |
Finance Lease, Liability | 73 | [2] |
Operating Lease, Liability, Current | 12 | [1] |
Finance Lease, Liability, Current | 10 | [2] |
Operating Lease, Liability, Noncurrent | 170 | [1] |
Finance Lease, Liability, Noncurrent | $ 63 | [2] |
[1] | The lease liabilities associated with our operating leases as of December 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Balance Sheet. | |
[2] | The lease liabilities associated with our finance leases as of December 31, 2019 are included in debt, current portion and debt, net of current portion on our Consolidated Balance Sheet. |
Leases Supplemental Balance She
Leases Supplemental Balance Sheet Information (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Property, Plant and Equipment, Gross | $ 18,354 | $ 18,187 | |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | (6,851) | (6,832) | |
Property, Plant and Equipment, Net | 11,963 | $ 12,442 | |
Operating Lease, Right-of-Use Asset | [1] | $ 171 | |
Operating Lease, Weighted Average Remaining Lease Term | 17 years 6 months | ||
Finance Lease, Weighted Average Remaining Lease Term | 6 years 9 months 18 days | ||
Operating Lease, Weighted Average Discount Rate, Percent | 5.10% | ||
Finance Lease, Weighted Average Discount Rate, Percent | 8.00% | ||
Property Subject to Finance Lease [Member] | |||
Property, Plant and Equipment, Gross | [2] | $ 212 | |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | [2] | (105) | |
Property, Plant and Equipment, Net | [2] | $ 107 | |
[1] | The right-of-use assets associated with our operating leases as of December 31, 2019 are included in other assets on our Consolidated Balance Sheet. | ||
[2] | The right-of-use assets associated with our finance leases as of December 31, 2019 are included in property, plant and equipment, net on our Consolidated Balance Sheet. |
Leases Supplemental Cash Flow I
Leases Supplemental Cash Flow Information (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Supplemental Cash Flow Information [Abstract] | |
Operating Lease, Payments | $ 54 |
Finance Lease, Interest Payment on Liability | 8 |
Finance Lease, Principal Payments | 11 |
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability | 14 |
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability | $ 0 |
Leases Operating Leases Future
Leases Operating Leases Future Minimum Payments Receivable (Details) $ in Millions | Dec. 31, 2019USD ($) |
Operating Leases, Future Minimum Payments Receivable [Abstract] | |
Lessor, Operating Lease, Payments to be Received, Remainder of Fiscal Year | $ 286 |
Lessor, Operating Lease, Payments to be Received, Two Years | 261 |
Lessor, Operating Lease, Payments to be Received, Three Years | 226 |
Lessor, Operating Lease, Payments to be Received, Four Years | 144 |
Lessor, Operating Lease, Payments to be Received, Five Years | 50 |
Lessor, Operating Lease, Payments to be Received, Thereafter | 236 |
Lessor, Operating Lease, Payments to be Received | $ 1,203 |
Leases Assets subject to contra
Leases Assets subject to contracts accounted for as operating leases (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Property, Plant and Equipment, Gross | $ 18,354 | $ 18,187 | |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | (6,851) | (6,832) | |
Property, Plant and Equipment, Net | 11,963 | $ 12,442 | |
Property Subject to Operating Lease [Member] | |||
Property, Plant and Equipment, Gross | 2,561 | ||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | (770) | ||
Property, Plant and Equipment, Net | [1] | $ 1,791 | |
[1] | Our assets subject to contracts that are accounted for as operating leases primarily consist of our power plants subject to tolling contracts. |
Leases Maturity of Operating Le
Leases Maturity of Operating Lease Liability (Details) $ in Millions | Dec. 31, 2018USD ($) | |
Assets subject to contracts accounted for as operating leases [Abstract] | ||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | $ 50 | [1] |
Capital Leases, Future Minimum Payments Due, Next Twelve Months | 40 | [2] |
Operating Leases, Future Minimum Payments, Due in Two Years | 19 | [1] |
Capital Leases, Future Minimum Payments Due in Two Years | 40 | [2] |
Operating Leases, Future Minimum Payments, Due in Three Years | 20 | [1] |
Capital Leases, Future Minimum Payments Due in Three Years | 38 | [2] |
Operating Leases, Future Minimum Payments, Due in Four Years | 18 | [1] |
Capital Leases, Future Minimum Payments Due in Four Years | 33 | [2] |
Operating Leases, Future Minimum Payments, Due in Five Years | 17 | [1] |
Capital Leases, Future Minimum Payments Due in Five Years | 27 | [2] |
Operating Leases, Future Minimum Payments, Due Thereafter | 192 | [1] |
Capital Leases, Future Minimum Payments Due Thereafter | 92 | [2] |
Operating Leases, Future Minimum Payments Due | 316 | [1] |
Capital Leases, Future Minimum Payments Due | 270 | [2] |
Capital Leases, Future Minimum Payments, Interest Included in Payments | 89 | [2] |
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments | $ 181 | [2] |
[1] | During the years ended December 31, 2018 and 2017, expense for operating leases amounted to $53 million and $50 million, respectively. | |
[2] | Includes a failed sale-leaseback transaction related to our Pasadena Power Plant. |
Leases Future Minimum Rental Pa
Leases Future Minimum Rental Payments for Operating Leases (Details) $ in Millions | Dec. 31, 2018USD ($) |
Future Minimum Rental Payments for Operating Leases [Abstract] | |
Operating Leases, Future Minimum Payments Receivable, Current | $ 342 |
Operating Leases, Future Minimum Payments Receivable, in Two Years | 261 |
Operating Leases, Future Minimum Payments Receivable, in Three Years | 257 |
Operating Leases, Future Minimum Payments Receivable, in Four Years | 224 |
Operating Leases, Future Minimum Payments Receivable, in Five Years | 141 |
Operating Leases, Future Minimum Payments Receivable, Thereafter | 239 |
Operating Leases, Future Minimum Payments Receivable | $ 1,464 |
Acquisitions, Divestitures an_2
Acquisitions, Divestitures and Discontinued Operations (Textuals) (Details) $ in Millions | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||
Sep. 30, 2019USD ($) | Mar. 31, 2017USD ($) | Sep. 30, 2019USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Jul. 10, 2019MW | Jan. 17, 2017USD ($) | ||
Business Acquisition [Line Items] | |||||||||
Dividends | [1] | $ 1,151 | $ 20 | $ 0 | |||||
Impairment losses | 84 | 10 | 41 | ||||||
(Gain) on sale of power plants, net | 10 | $ 0 | 27 | ||||||
North American Power [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Ownership Percentage of Acquiree | 100.00% | ||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | $ 105 | ||||||||
Garrison Energy Center LLC [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Power generation capacity | MW | 309 | ||||||||
RockGen Energy LLC [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Power generation capacity | MW | 503 | ||||||||
Garrison Energy Center and RockGen Energy LLC [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Ownership Percentage of Divestee | 100.00% | ||||||||
Proceeds from Sale of Productive Assets | $ 360 | ||||||||
Impairment losses | $ 55 | ||||||||
Osprey Energy Center [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Proceeds from Sale of Productive Assets | $ 166 | ||||||||
(Gain) on sale of power plants, net | $ 27 | ||||||||
Commodity Contract [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Proceeds from Hedge, Financing Activities | $ 52 | ||||||||
Dividend Paid [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Dividends | $ 400 | ||||||||
[1] | Dividends paid during the years ended December 31, 2019 and 2018, includes approximately $1 million and $20 million, respectively, in certain Merger-related costs incurred by CPN Management, our parent. |
Property, Plant and Equipment_3
Property, Plant and Equipment, Net (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Property, Plant and Equipment [Line Items] | |||
Buildings, machinery and equipment | $ 16,510 | $ 16,400 | |
Geothermal properties | 1,553 | 1,501 | |
Other | 291 | 286 | |
Property, Plant and Equipment, Gross | 18,354 | 18,187 | |
Less: Accumulated depreciation | 6,851 | 6,832 | |
Property, Plant and Equipment, Gross, Less Accumulated Depreciation | 11,503 | 11,355 | |
Land | 128 | 121 | |
Construction in progress | 332 | 966 | |
Property, plant and equipment, net | 11,963 | 12,442 | |
Depreciation | 627 | 684 | $ 638 |
Interest Costs, Capitalized During Period | $ 12 | $ 29 | $ 26 |
Rotable Parts [Member] | Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Estimated Useful Lives | 1 year 6 months | ||
Building, Machinery and Equipment, Gross [Member] | Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Estimated Useful Lives | 50 years | ||
Geothermal Properties, Gross [Member] | Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Estimated Useful Lives | 13 years | ||
Geothermal Properties, Gross [Member] | Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Estimated Useful Lives | 58 years | ||
Property, Plant and Equipment, Other Types [Member] | Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Estimated Useful Lives | 3 years | ||
Property, Plant and Equipment, Other Types [Member] | Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Estimated Useful Lives | 50 years |
Variable Interest Entities an_3
Variable Interest Entities and Unconsolidated Investments (Unconsolidated VIEs) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Equity Method Investments Included on Balance Sheet [Abstract] | |||
Equity Method Investments | $ 70 | $ 76 | |
Greenfield [Member] | |||
Equity Method Investments Included on Balance Sheet [Abstract] | |||
Equity Method Investments | [1] | $ 66 | 55 |
Equity Method Investment, Ownership Percentage | [1] | 50.00% | |
Whitby [Member] | |||
Equity Method Investments Included on Balance Sheet [Abstract] | |||
Equity Method Investments | [2] | $ 0 | 15 |
Equity Method Investment, Ownership Percentage | [2] | 0.00% | |
Calpine Receivables [Member] | |||
Equity Method Investments Included on Balance Sheet [Abstract] | |||
Equity Method Investments | $ 4 | $ 6 | |
Equity Method Investment, Ownership Percentage | 100.00% | ||
[1] | Includes our share of accumulated other comprehensive income/loss related to interest rate hedging instruments associated with our unconsolidated subsidiary Greenfield LP’s debt. | ||
[2] | On November 20, 2019, we sold our 50% interest in Whitby to a third party and recorded a gain on sale of assets, net of approximately $5 million. |
Variable Interest Entities an_4
Variable Interest Entities and Unconsolidated Investments (Unconsolidated Investements) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items] | ||||
(Income) from unconsolidated subsidiaries | $ (22) | $ (24) | $ (22) | |
Distributions from Equity Method Investments | 26 | 53 | 28 | |
Greenfield [Member] | ||||
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items] | ||||
(Income) from unconsolidated subsidiaries | (13) | (11) | (14) | |
Distributions from Equity Method Investments | 0 | 48 | 8 | |
Whitby [Member] | ||||
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items] | ||||
(Income) from unconsolidated subsidiaries | [1] | (11) | (15) | (10) |
Distributions from Equity Method Investments | [1] | 26 | 5 | 20 |
Calpine Receivables [Member] | ||||
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items] | ||||
(Income) from unconsolidated subsidiaries | 2 | 2 | 2 | |
Distributions from Equity Method Investments | $ 0 | $ 0 | $ 0 | |
[1] | On November 20, 2019, we sold our 50% interest in Whitby to a third party. |
Variable Interest Entities an_5
Variable Interest Entities and Unconsolidated Investments (VIE Textuals) (Details) $ in Millions | Jan. 01, 2020USD ($) | Dec. 31, 2019USD ($)yrMW | Dec. 31, 2019USD ($)yrMW | Dec. 31, 2018USD ($)MW | Dec. 31, 2017USD ($) | Nov. 20, 2019 | |
Schedule of Equity Method Investments [Line Items] | |||||||
Proceeds from sale of power plants and other | [1] | $ 322 | $ 11 | $ 162 | |||
Gain (Loss) on Disposition of Assets | 10 | 0 | $ 27 | ||||
Equity Method Investment, Summarized Financial Information, Debt | $ 299 | 299 | 301 | ||||
Prorata Share of Equity Method Investment, Summarized Financial Information, Debt | 150 | 150 | 151 | ||||
Long-term Debt | $ 11,857 | 11,857 | $ 10,156 | ||||
Put Option [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Proceeds from sale of power plants and other | 280 | ||||||
Call Option [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Proceeds from sale of power plants and other | $ 377 | ||||||
Russell City Energy [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Minority Interest Ownership Percentage By Noncontrolling Third Party Owners | 25.00% | 25.00% | |||||
Equity Method Investment, Ownership Percentage | 75.00% | 75.00% | |||||
Variable Interest Entity, Primary Beneficiary [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Power generation capacity | MW | 6,669 | 6,669 | 7,880 | ||||
Inland Empire Energy Center [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Power generation capacity | MW | 775 | 775 | |||||
Put Option Exercise Period | yr | 2,025 | 2,025 | |||||
Minimum [Member] | Inland Empire Energy Center [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Call Option Exercise Period | yr | 2,017 | 2,017 | |||||
Maximum [Member] | Inland Empire Energy Center [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Call Option Exercise Period | yr | 2,024 | 2,024 | |||||
Calpine Receivables [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount | $ 48 | $ 48 | |||||
Equity Method Investment, Ownership Percentage | 100.00% | 100.00% | |||||
Greenfield [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Power generation capacity | MW | 1,038 | 1,038 | |||||
Equity Method Investment, Ownership Percentage | [2] | 50.00% | 50.00% | ||||
Whitby [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Power generation capacity | MW | 50 | 50 | |||||
Equity Method Investment, Ownership Percentage | [3] | 0.00% | 0.00% | ||||
Equity Method Investment Ownership Interest Sold | 50.00% | ||||||
Gain (Loss) on Disposition of Assets | $ 5 | ||||||
OMEC [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Long-term Debt | [4] | $ 0 | $ 0 | $ 218 | |||
Subsequent Event [Member] | Russell City Energy [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Payments to Acquire Businesses, Net of Cash Acquired | $ 49 | ||||||
[1] | Dividends paid during the years ended December 31, 2019 and 2018, includes approximately $1 million and $20 million, respectively, in certain Merger-related costs incurred by CPN Management, our parent. | ||||||
[2] | Includes our share of accumulated other comprehensive income/loss related to interest rate hedging instruments associated with our unconsolidated subsidiary Greenfield LP’s debt. | ||||||
[3] | On November 20, 2019, we sold our 50% interest in Whitby to a third party and recorded a gain on sale of assets, net of approximately $5 million. | ||||||
[4] | On August 14, 2019, we repaid the project debt associated with OMEC from a portion of the proceeds received from the issuance of our 2026 First Lien Term Loans (as discussed above), together with cash on hand. |
Debt (Debt) (Details)
Debt (Debt) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Debt Instrument [Line Items] | ||
Debt and Lease Obligation | $ 11,706 | $ 10,785 |
Debt, current portion | 1,268 | 637 |
Debt, net of current portion | 10,438 | 10,148 |
Unsecured Debt [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Lease Obligation | 3,663 | 3,036 |
Loans Payable [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Lease Obligation | 3,167 | 2,976 |
Corporate Debt Securities [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Lease Obligation | 2,835 | 2,400 |
Notes Payable, Other Payables [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Lease Obligation | 879 | 1,264 |
Secured Debt [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Lease Obligation | 967 | 974 |
Finance Lease Obligations [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Lease Obligation | 73 | 105 |
Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Lease Obligation | $ 122 | $ 30 |
Debt (Annual Debt Marturities)
Debt (Annual Debt Marturities) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Long-term Debt, Fiscal Year Maturity [Abstract] | ||
2017 | $ 1,269 | |
2018 | 347 | |
2019 | 230 | |
2020 | 198 | |
2021 | 2,030 | |
Thereafter | 7,771 | |
Total debt, gross | 11,845 | |
Debt Issuance Costs, Net | 114 | |
Less: Discount | 25 | |
Debt and Lease Obligation | $ 11,706 | $ 10,785 |
Debt Senior Unsecured Notes (De
Debt Senior Unsecured Notes (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 31, 2015 | Sep. 30, 2014 | ||
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 11,857 | $ 11,857 | $ 10,156 | ||||
Debt Instrument, Interest Rate, Effective Percentage | 5.80% | 5.80% | 5.70% | ||||
Debt Issuance Costs, Net | $ 114 | $ 114 | |||||
Gains (Losses) on Extinguishment of Debt | (58) | $ 28 | $ (38) | ||||
Senior Unsecured Notes 2023 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | [1] | $ 623 | $ 623 | $ 1,227 | |||
Debt Instrument, Interest Rate, Effective Percentage | [2] | 5.70% | 5.70% | 5.60% | |||
Debt Instrument, Face Amount | $ 1,250 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.375% | ||||||
Gains (Losses) on Extinguishment of Debt | $ 24 | $ 0 | $ 1 | ||||
Senior Unsecured Notes 2024 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 479 | $ 479 | $ 599 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [2] | 5.70% | 5.70% | 5.70% | |||
Debt Instrument, Face Amount | $ 650 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | ||||||
Gains (Losses) on Extinguishment of Debt | $ (1) | $ 4 | |||||
Senior Unsecured Notes 2025 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 1,174 | $ 1,174 | $ 1,210 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [2] | 5.80% | 5.80% | 6.00% | |||
Debt Instrument, Face Amount | $ 1,550 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.75% | ||||||
Gains (Losses) on Extinguishment of Debt | $ 3 | $ 30 | |||||
Senior Unsecured Notes 2028 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | [1] | $ 1,387 | $ 1,387 | $ 0 | |||
Debt Instrument, Interest Rate, Effective Percentage | [2] | 5.30% | 5.30% | 0.00% | |||
Debt Instrument, Face Amount | $ 1,400 | $ 1,400 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.125% | 5.125% | |||||
Debt Issuance Costs, Net | $ 13 | $ 13 | |||||
Unsecured Debt [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 3,663 | 3,663 | $ 3,036 | ||||
Gains (Losses) on Extinguishment of Debt | $ 2 | $ 35 | |||||
[1] | On December 27, 2019, we used the proceeds from the issuance of our 2028 Senior Unsecured Notes (discussed below) to redeem approximately $613 million in aggregate principal amount of our 2023 Senior Unsecured Notes, plus accrued and unpaid interest. On January 21, 2020, we redeemed the remaining $623 million in aggregate principal amount of our 2023 Senior Unsecured Notes, which was included in debt, current portion on our Consolidated Balance Sheet at December 31, 2019, with the proceeds from the 2028 Senior Unsecured Notes, which was included in cash and cash equivalents on our Consolidated Balance Sheet at December 31, 2019. We recorded approximately $24 million in loss on extinguishment of debt which is comprised of approximately $18 million of prepayment premiums and approximately $6 million associated with the write-off of unamortized debt issuance costs during the fourth quarter of 2019 associated with the redemption. | ||||||
[2] | Our weighted average interest rate calculation includes the amortization of debt issuance costs. |
Debt Debt Repurchases (Details)
Debt Debt Repurchases (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Debt Instrument, Redemption [Line Items] | ||||
Gains (Losses) on Extinguishment of Debt | $ (58) | $ 28 | $ (38) | |
Senior Unsecured Notes 2023 [Member] | ||||
Debt Instrument, Redemption [Line Items] | ||||
Debt Instrument, Repurchased Face Amount | $ 0 | 0 | 14 | |
Debt Instrument, Repurchase Amount | 0 | 0 | 13 | |
Gains (Losses) on Extinguishment of Debt | 24 | 0 | 1 | |
Write off of Deferred Debt Issuance Cost | 6 | |||
Unsecured Debt [Member] | ||||
Debt Instrument, Redemption [Line Items] | ||||
Debt Instrument, Repurchased Face Amount | 160 | 160 | 390 | |
Debt Instrument, Repurchase Amount | 158 | 158 | 355 | |
Gains (Losses) on Extinguishment of Debt | 2 | 35 | ||
Write off of Deferred Debt Issuance Cost | 3 | |||
Senior Unsecured Notes 2024 [Member] | ||||
Debt Instrument, Redemption [Line Items] | ||||
Debt Instrument, Repurchased Face Amount | 122 | 122 | 46 | |
Debt Instrument, Repurchase Amount | 123 | 123 | 42 | |
Gains (Losses) on Extinguishment of Debt | (1) | 4 | ||
Senior Unsecured Notes 2025 [Member] | ||||
Debt Instrument, Redemption [Line Items] | ||||
Debt Instrument, Repurchased Face Amount | 38 | 38 | 330 | |
Debt Instrument, Repurchase Amount | $ 35 | 35 | 300 | |
Gains (Losses) on Extinguishment of Debt | $ 3 | $ 30 |
Debt Debt (First Lien Term Loan
Debt Debt (First Lien Term Loans) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||
Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Aug. 12, 2019 | Apr. 05, 2019 | ||
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 11,857 | $ 10,156 | |||||
Debt Instrument, Interest Rate, Effective Percentage | 5.80% | 5.70% | |||||
Debt Issuance Costs, Net | $ 114 | ||||||
Gains (Losses) on Extinguishment of Debt | (58) | $ 28 | $ (38) | ||||
New 2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Face Amount | $ 750 | ||||||
Percentage of principal amount of Term Loan to be paid quarterly | 0.25% | ||||||
Debt Instrument Unamortized Discount Percent | 0.50% | ||||||
Debt Issuance Costs, Net | $ 11 | ||||||
2023 First Lien Term Loan and OMEC Project Debt [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Gains (Losses) on Extinguishment of Debt | $ (12) | ||||||
2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Face Amount | $ 950 | ||||||
Percentage of principal amount of Term Loan to be paid quarterly | 0.25% | ||||||
Debt Instrument Unamortized Discount Percent | 1.00% | ||||||
Debt Issuance Costs, Net | $ 7 | ||||||
First Lien Term Loan 2019 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 0 | $ 389 | |||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 0.00% | 4.90% | ||||
2023 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 0 | $ 1,059 | |||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 0.00% | 5.40% | ||||
2024 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | [2] | $ 1,514 | $ 1,528 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 5.30% | 5.00% | ||||
2026 First Lien Term Loans [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 1,653 | $ 0 | |||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 5.40% | 0.00% | ||||
Loans Payable [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 3,167 | $ 2,976 | |||||
2019 and 2023 First Lien Term Loans [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Gains (Losses) on Extinguishment of Debt | $ (3) | ||||||
Federal Funds Effective Rate [Member] | New 2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | ||||||
Federal Funds Effective Rate [Member] | 2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | ||||||
Eurodollar Rate For A One-Month Interest Period [Member] | New 2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | ||||||
Eurodollar Rate For A One-Month Interest Period [Member] | 2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | ||||||
Prime Rate Or The Eurodollar Rate For a One Month Interest Period [Member] | New 2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | ||||||
Prime Rate Or The Eurodollar Rate For a One Month Interest Period [Member] | 2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 1.25% | ||||||
London Interbank Offered Rate (LIBOR) [Member] | New 2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 2.00% | ||||||
London Interbank Offered Rate (LIBOR) [Member] | 2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 2.25% | ||||||
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | New 2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 0.00% | ||||||
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | 2026 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 0.00% | ||||||
[1] | Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. | ||||||
[2] | Our 2024 First Lien Term Loan, which matures on January 15, 2024, carries substantially similar terms as our $950 million first lien senior secured term loan as discussed below. |
Debt Debt (First Lien Notes) (D
Debt Debt (First Lien Notes) (Details) - USD ($) $ in Millions | Jan. 01, 2020 | Dec. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Jun. 30, 2016 | |
Debt Instrument [Line Items] | |||||||
Gains (Losses) on Extinguishment of Debt | $ (58) | $ 28 | $ (38) | ||||
Long-term Debt | $ 11,857 | $ 11,857 | $ 10,156 | ||||
Debt Instrument, Interest Rate, Effective Percentage | 5.80% | 5.80% | 5.70% | ||||
Debt Issuance Costs, Net | $ 114 | $ 114 | |||||
Long-term Debt, Gross | 11,845 | 11,845 | |||||
2022 First Lien Notes [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Early Repayment of Senior Debt | (505) | ||||||
Gains (Losses) on Extinguishment of Debt | 6 | ||||||
Redemption Premium | 1 | ||||||
Long-term Debt | $ 245 | $ 245 | $ 743 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 6.40% | 6.40% | 6.40% | |||
Write off of Deferred Debt Issuance Cost | $ 5 | ||||||
2024 First Lien Notes [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Early Repayment of Senior Debt | (306) | ||||||
Gains (Losses) on Extinguishment of Debt | 14 | ||||||
Redemption Premium | 11 | ||||||
Long-term Debt | $ 184 | $ 184 | $ 486 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 6.10% | 6.10% | 6.10% | |||
Write off of Deferred Debt Issuance Cost | $ 3 | ||||||
2028 First Lien Notes [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Face Amount | 1,250 | $ 1,250 | |||||
Long-term Debt | $ 1,234 | $ 1,234 | $ 0 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 4.70% | 4.70% | 0.00% | |||
Debt Instrument, Interest Rate, Stated Percentage | 4.50% | 4.50% | |||||
Debt Issuance Costs, Net | $ 16 | $ 16 | |||||
2026 First Lien Notes [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Face Amount | $ 560 | $ 625 | |||||
Long-term Debt | $ 1,172 | $ 1,172 | $ 1,171 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 5.50% | 5.50% | 5.50% | |||
Debt Instrument, Interest Rate, Stated Percentage | 5.25% | 5.25% | |||||
Debt Issuance Costs, Net | $ 8 | $ 9 | |||||
Corporate Debt Securities [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 2,835 | $ 2,835 | $ 2,400 | ||||
Subsequent Event [Member] | 2022 First Lien Notes [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Early Repayment of Senior Debt | $ (245) | ||||||
Subsequent Event [Member] | 2024 First Lien Notes [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Early Repayment of Senior Debt | $ (184) | ||||||
[1] | Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. |
Debt (Project Financing, Notes
Debt (Project Financing, Notes Payable and Others) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Debt Instrument [Line Items] | |||
Long-term Debt | $ 11,857 | $ 10,156 | |
Debt Instrument, Interest Rate, Effective Percentage | 5.80% | 5.70% | |
Russell City Project [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 272 | $ 341 | |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 6.60% | 6.50% |
Steamboat [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 351 | $ 384 | |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 4.60% | 4.50% |
OMEC [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | [2] | $ 0 | $ 218 |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 0.00% | 7.10% |
Los Esteros Project [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 135 | $ 163 | |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 5.20% | 4.70% |
Pasadena [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | [3] | $ 62 | $ 76 |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 8.90% | 8.90% |
Bethpage [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | [4] | $ 45 | $ 53 |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 7.00% | 7.10% |
Other Debt Obligations [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 14 | $ 29 | |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 0.00% | 0.00% |
Project Financing Total [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 879 | $ 1,264 | |
[1] | Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. | ||
[2] | On August 14, 2019, we repaid the project debt associated with OMEC from a portion of the proceeds received from the issuance of our 2026 First Lien Term Loans (as discussed above), together with cash on hand. | ||
[3] | Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP. | ||
[4] | Represents a weighted average of first and second lien loans for the weighted average effective interest rates. |
Debt CCFC Term Loans (Details)
Debt CCFC Term Loans (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Debt Instrument [Line Items] | |||||
Debt Issuance Costs, Net | $ 114 | ||||
Long-term Debt | $ 11,857 | $ 10,156 | |||
Debt Instrument, Interest Rate, Effective Percentage | 5.80% | 5.70% | |||
Gains (Losses) on Extinguishment of Debt | $ (58) | $ 28 | $ (38) | ||
Secured Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Debt | $ 967 | $ 974 | |||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 5.20% | 4.90% | ||
New CCFC Term Loans [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Issuance Costs, Net | $ 13 | 13 | |||
Debt Instrument, Face Amount | $ 1,000 | $ 1,000 | |||
Long Term Debt net of Original Issuance Disount | 99.875% | ||||
Percentage of principal amount of Term Loan to be paid quarterly | 0.25% | ||||
Minimum Partial Prepayment Amount | $ 1 | ||||
CCFC Term Loans [Member] | |||||
Debt Instrument [Line Items] | |||||
Gains (Losses) on Extinguishment of Debt | $ (12) | ||||
Federal Funds Effective Rate [Member] | New CCFC Term Loans [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | ||||
Eurodollar Rate For A One-Month Interest Period [Member] | New CCFC Term Loans [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | ||||
Prime Rate Or The Eurodollar Rate For a One Month Interest Period [Member] | New CCFC Term Loans [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | ||||
London Interbank Offered Rate (LIBOR) [Member] | New CCFC Term Loans [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 2.00% | ||||
[1] | Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. |
Debt (Corporate Revolving Facil
Debt (Corporate Revolving Facility and other Letters of Credit Facilities) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Sep. 30, 2019 | Jun. 30, 2019 | Dec. 31, 2019 | Aug. 12, 2019 | Apr. 05, 2019 | Dec. 31, 2018 | |
Line of Credit Facility [Line Items] | ||||||
Debt and Lease Obligation | $ 11,706 | $ 10,785 | ||||
Letters of Credit Outstanding, Amount | 1,085 | 1,365 | ||||
CDHI [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt and Lease Obligation | $ 122 | |||||
Applicable margin range percentage above base rate | 1.75% | |||||
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates | 2.75% | |||||
Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Letters of Credit Outstanding, Amount | $ 604 | 693 | ||||
Revolving Credit Facility [Member] | Amendment No. 9 [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Increase (Decrease), Net | $ 330 | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,020 | |||||
Revolving Credit Facility [Member] | Amendment No. 8 [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,690 | |||||
Revolving Credit Facility [Member] | Amendment No. 10 [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Increase (Decrease), Net | $ 20 | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,000 | |||||
Total Letter of Credit Sub-limit | $ 150 | |||||
Standby Letters of Credit [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Letters of Credit Outstanding, Amount | 3 | 251 | ||||
Various Project Financing Facilities [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Letters of Credit Outstanding, Amount | 184 | 228 | ||||
Other Corporate Facilities [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Letters of Credit Outstanding, Amount | 294 | 193 | ||||
Line of Credit Facility, Maximum Borrowing Capacity | 300 | |||||
Other Corporate Facilities [Member] | Goldman Sachs Facility 2 [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | 100 | |||||
Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt and Lease Obligation | $ 122 | $ 30 |
Debt (Fair Value of Debt) (Deta
Debt (Fair Value of Debt) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | $ 11,857 | $ 10,156 | |
Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 11,571 | 10,604 | |
Unsecured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 3,663 | 3,036 | |
Unsecured Debt [Member] | Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 3,663 | 3,036 | |
Loans Payable [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 3,167 | 2,976 | |
Loans Payable [Member] | Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 3,167 | 2,976 | |
Corporate Debt Securities [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,835 | 2,400 | |
Corporate Debt Securities [Member] | Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,835 | 2,400 | |
Notes Payable, Other Payable excluding Capital Leases [Member] | Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | [1] | 817 | 1,188 |
Secured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 967 | 974 | |
Secured Debt [Member] | Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 967 | 974 | |
Revolving Credit Facility [Member] | Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 122 | 30 | |
Fair Value, Inputs, Level 2 [Member] | Unsecured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 3,764 | 2,803 | |
Fair Value, Inputs, Level 2 [Member] | Loans Payable [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 3,238 | 2,877 | |
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,929 | 2,299 | |
Fair Value, Inputs, Level 2 [Member] | Secured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 982 | 938 | |
Fair Value, Inputs, Level 3 [Member] | Notes Payable, Other Payable excluding Capital Leases [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | [1] | 822 | 1,209 |
Fair Value, Inputs, Level 3 [Member] | Revolving Credit Facility [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | $ 122 | $ 30 | |
[1] | Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP. |
Debt (Textuals) (Details)
Debt (Textuals) (Details) - USD ($) $ in Millions | Jan. 01, 2020 | Dec. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Jun. 30, 2019 | Jun. 30, 2016 | Sep. 30, 2014 | |
Debt Instrument [Line Items] | |||||||||
Repayments of Unsecured Debt | $ 768 | $ 355 | $ 453 | ||||||
Debt Instrument, Interest Rate, Effective Percentage | 5.80% | 5.80% | 5.70% | ||||||
Gains (Losses) on Extinguishment of Debt | $ (58) | $ 28 | (38) | ||||||
Senior Unsecured Notes 2028 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 5.30% | 5.30% | 0.00% | |||||
Debt Instrument, Face Amount | $ 1,400 | $ 1,400 | |||||||
Revolving Credit Facility [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Repayment time for drawings under letters of credit | 2 days | ||||||||
Revolving Credit Facility [Member] | Minimum [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Applicable margin range percentage above base rate | 1.00% | ||||||||
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates | 2.00% | ||||||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.25% | ||||||||
Revolving Credit Facility [Member] | Maximum [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Applicable margin range percentage above base rate | 1.25% | ||||||||
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates | 2.25% | ||||||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.50% | ||||||||
2023 First Lien Term Loan [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Effective Percentage | [2] | 0.00% | 0.00% | 5.40% | |||||
CDHI [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Letter of Credit Total | $ 300 | $ 300 | |||||||
2026 First Lien Notes [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Effective Percentage | [3] | 5.50% | 5.50% | 5.50% | |||||
Debt Instrument, Face Amount | $ 560 | $ 625 | |||||||
Senior Unsecured Notes 2023 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Repayments of Unsecured Debt | $ (613) | ||||||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 5.70% | 5.70% | 5.60% | |||||
Gains (Losses) on Extinguishment of Debt | $ 24 | $ 0 | $ 1 | ||||||
Debt Instrument, Face Amount | $ 1,250 | ||||||||
Redemption Premium | 18 | ||||||||
Write off of Deferred Debt Issuance Cost | 6 | ||||||||
Russell City and Los Esteros Project Debt [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term Debt, Excluding Current Maturities | 304 | $ 304 | |||||||
One Month [Member] | Revolving Credit Facility [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Interest periods for LIBOR rate borrowings | 1 month | ||||||||
Two Months [Member] | Revolving Credit Facility [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Interest periods for LIBOR rate borrowings | 2 months | ||||||||
Three Months [Member] | Revolving Credit Facility [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Interest periods for LIBOR rate borrowings | 3 months | ||||||||
Six Months [Member] | Revolving Credit Facility [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Interest periods for LIBOR rate borrowings | 6 months | ||||||||
Nine Months [Member] | Revolving Credit Facility [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Interest periods for LIBOR rate borrowings | 9 months | ||||||||
Twelve Months [Member] | Revolving Credit Facility [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Interest periods for LIBOR rate borrowings | 12 months | ||||||||
Federal Funds Effective Rate [Member] | Revolving Credit Facility [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | ||||||||
CDHI [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Future Line of Credit Facility Maximum Borrowing Capacity | 125 | $ 125 | |||||||
Applicable margin range percentage above base rate | 1.75% | ||||||||
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates | 2.75% | ||||||||
Other Corporate Facilities [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 300 | $ 300 | |||||||
Other Corporate Facilities [Member] | Goldman Sachs [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 150 | 150 | |||||||
Other Corporate Facilities [Member] | Citi Bank [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 50 | $ 50 | |||||||
Revolving Credit Facility [Member] | Amendment No. 8 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,690 | ||||||||
Subsequent Event [Member] | Senior Unsecured Notes 2023 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Repayments of Unsecured Debt | $ (623) | ||||||||
[1] | Our weighted average interest rate calculation includes the amortization of debt issuance costs. | ||||||||
[2] | Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. | ||||||||
[3] | Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. |
Assets and Liabilities with R_3
Assets and Liabilities with Recurring Fair Value Measurements (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and Cash Equivalents, Fair Value Disclosure | [1] | $ 784 | $ 168 |
Derivative Asset | [2] | 402 | 302 |
Effect of Netting and Allocation of Collateral, Asset | [3],[4] | (1,021) | (1,221) |
Margin Deposit Assets | [5] | 432 | 343 |
Assets, Fair Value Disclosure | 1,186 | 470 | |
Derivative Liability | [2] | 288 | 443 |
Effect of Netting and Allocation of Collateral, Liability | [3],[4] | (1,135) | (1,268) |
Margin deposits posted with us by our counterparties | [5],[6] | 127 | 52 |
Liabilities, Fair Value Disclosure | 288 | 443 | |
Fair Value, Inputs, Level 1 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and Cash Equivalents, Fair Value Disclosure | [1] | 784 | 168 |
Effect of Netting and Allocation of Collateral, Asset | [3],[4] | (872) | (933) |
Assets, Fair Value Disclosure | 784 | 168 | |
Effect of Netting and Allocation of Collateral, Liability | [3],[4] | (984) | (932) |
Liabilities, Fair Value Disclosure | 0 | 0 | |
Fair Value, Inputs, Level 2 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and Cash Equivalents, Fair Value Disclosure | [1] | 0 | 0 |
Effect of Netting and Allocation of Collateral, Asset | [3],[4] | (131) | (262) |
Assets, Fair Value Disclosure | 126 | 116 | |
Effect of Netting and Allocation of Collateral, Liability | [3],[4] | (133) | (310) |
Liabilities, Fair Value Disclosure | 183 | 249 | |
Fair Value, Inputs, Level 3 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and Cash Equivalents, Fair Value Disclosure | [1] | 0 | 0 |
Effect of Netting and Allocation of Collateral, Asset | [3],[4] | (18) | (26) |
Assets, Fair Value Disclosure | 276 | 186 | |
Effect of Netting and Allocation of Collateral, Liability | [3],[4] | (18) | (26) |
Liabilities, Fair Value Disclosure | 105 | 194 | |
Forward Contracts [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | [7] | 539 | 550 |
Derivative Liability | [7] | 408 | 769 |
Forward Contracts [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | [7] | 0 | 0 |
Derivative Liability | [7] | 0 | 0 |
Forward Contracts [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | [7] | 245 | 338 |
Derivative Liability | [7] | 285 | 549 |
Forward Contracts [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | [7] | 294 | 212 |
Derivative Liability | [7] | 123 | 220 |
Future [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | 872 | 933 | |
Derivative Liability | 984 | 932 | |
Future [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | 872 | 933 | |
Derivative Liability | 984 | 932 | |
Future [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | 0 | 0 | |
Derivative Liability | 0 | 0 | |
Future [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | 0 | 0 | |
Derivative Liability | 0 | 0 | |
Interest Rate Contract [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | 12 | 40 | |
Derivative Liability | 31 | 10 | |
Interest Rate Contract [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | 0 | 0 | |
Derivative Liability | 0 | 0 | |
Interest Rate Contract [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | 12 | 40 | |
Derivative Liability | 31 | 10 | |
Interest Rate Contract [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | 0 | 0 | |
Derivative Liability | $ 0 | $ 0 | |
[1] | As of December 31, 2019 and 2018, we had cash equivalents of $573 million and $23 million included in cash and cash equivalents and $211 million and $145 million included in restricted cash, respectively. | ||
[2] | At December 31, 2019 and 2018, we had $191 million and $244 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Balance Sheets primarily related to initial margin requirements. | ||
[3] | Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $112 million, $2 million and nil, respectively, at December 31, 2019. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $(1) million, $48 million and nil, respectively, at December 31, 2018. | ||
[4] | We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 10 for further discussion of our derivative instruments subject to master netting arrangements. | ||
[5] | We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 10 for further discussion of our derivative instruments subject to master netting arrangements. | ||
[6] | At December 31, 2019 and 2018, $3 million and $32 million, respectively, were included in current and long-term derivative assets and liabilities, $93 million and $20 million, respectively, were included in other current liabilities and $31 million and nil, respectively, were included in other long-term liabilities on our Consolidated Balance Sheets. | ||
[7] | Includes OTC swaps and options. |
Assets and Liabilities with R_4
Assets and Liabilities with Recurring Fair Value Measurements Quantitative Information about Level 3 Fair Value Measurements (Details) - USD ($) | Dec. 31, 2019 | Dec. 31, 2018 | |
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Derivative, Fair Value, Net | [1] | $ 114,000,000 | $ (141,000,000) |
Physical Power [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Derivative, Fair Value, Net | [2] | 158,000,000 | 36,000,000 |
Physical Power [Member] | Minimum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | 4.85 | 2.12 | |
Physical Power [Member] | Maximum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | 184.15 | 227.98 | |
Natural Gas [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Derivative, Fair Value, Net | (20,000,000) | (73,000,000) | |
Natural Gas [Member] | Minimum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | 1.73 | 0.75 | |
Natural Gas [Member] | Maximum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | 6.45 | 8.87 | |
Power Congestion Products [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Derivative, Fair Value, Net | 17,000,000 | 26,000,000 | |
Power Congestion Products [Member] | Minimum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | (10.32) | (11.71) | |
Power Congestion Products [Member] | Maximum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | $ 20 | $ 11.88 | |
[1] | At December 31, 2019 and 2018, we had $191 million and $244 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Balance Sheets primarily related to initial margin requirements. | ||
[2] | Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy. |
Assets and Liabilities with R_5
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Fair Value Measurement [Domain] | ||||
Fair Value Disclosures [Abstract] | ||||
Cash and Cash Equivalents, at Carrying Value | $ 573 | $ 23 | ||
Cash Equivalents Included In Restricted Cash, Fair Value Disclosure | 211 | 145 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | (8) | 197 | $ 416 | |
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Still Held, Unrealized Gain (Loss) | 150 | (133) | 82 | |
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount | 0 | 0 | 0 | |
Included in operating revenues | [1] | 171 | (88) | 32 |
Included in fuel and purchased energy expense | [2] | (21) | (45) | 50 |
Amount of Change in Collateral of Financial Instruments Classified as Derivative Asset (Liability) | 0 | 0 | (17) | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases | 5 | 18 | 4 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Issues | (3) | (2) | (1) | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements | 56 | (86) | (179) | |
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount | 0 | 0 | 0 | |
Transfers into level 3 | [3],[4] | (1) | 0 | 2 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | [4],[5] | 30 | 2 | 106 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | 171 | (8) | 197 | |
Cash and Cash Equivalents, at Carrying Value | 1,131 | 205 | ||
Cash Equivalents Included In Restricted Cash, Fair Value Disclosure | 345 | 201 | ||
Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value Disclosures [Abstract] | ||||
Derivative, Collateral, Right to Reclaim Cash, Net | 112 | (1) | ||
Transfer to Level 2 [Member] | ||||
Purchases, issuances and settlements: | ||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | 30 | 2 | 104 | |
Fair Value Disclosures [Abstract] | ||||
Derivative, Collateral, Right to Reclaim Cash, Net | 2 | 48 | ||
Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value Disclosures [Abstract] | ||||
Derivative, Collateral, Right to Reclaim Cash, Net | $ 0 | $ 0 | ||
Other Assets [Member] | ||||
Purchases, issuances and settlements: | ||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | $ 2 | |||
[1] | For power contracts and other power-related products, included on our Consolidated Statements of Operations. | |||
[2] | For natural gas and power contracts, swaps and options, included on our Consolidated Statements of Operations. | |||
[3] | We had $1 million in gains, nil and $(2) million in losses transferred out of level 2 into level 3 for the years ended December 31, 2019, 2018 and 2017, respectively. | |||
[4] | We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 during the years ended December 31, 2019, 2018 and 2017. | |||
[5] | We had $30 million, $2 million and $104 million in gains transferred out of level 3 into level 2 during the years ended December 31, 2019, 2018 and 2017, respectively, due to changes in market liquidity in various power markets and $2 million in gains transferred out of level 3 during the years ended December 31, 2017, to other assets following the election of the normal purchase normal sales exemption and the discontinuance of derivative accounting treatment as of the date of this election for certain commodity contracts. |
Derivative Instruments (Details
Derivative Instruments (Details) $ in Billions | 12 Months Ended | |
Dec. 31, 2019USD ($)MMBTUMWht | Dec. 31, 2018USD ($)MMBTUMWht | |
Power [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | (184) | (161) |
Natural Gas [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | (1,063) | (1,045) |
Environmental Credits [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Mass | t | 26 | 13 |
Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional Amount | $ | $ 4.8 | $ 4.5 |
Derivative Instruments (Detai_2
Derivative Instruments (Details 2) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | [1] | $ 402 | $ 302 |
Derivative Liability | [1] | 288 | 443 |
Designated as Hedging Instrument [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | 12 | 40 | |
Derivative Liability | 29 | 10 | |
Not Designated as Hedging Instrument [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | 390 | 262 | |
Derivative Liability | 259 | 433 | |
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | 390 | 262 | |
Derivative Liability | 257 | 433 | |
Interest Rate Contract [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | 12 | 40 | |
Derivative Liability | 31 | 10 | |
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | 12 | 40 | |
Derivative Liability | $ 29 | $ 10 | |
[1] | At December 31, 2019 and 2018, we had $191 million and $244 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Balance Sheets primarily related to initial margin requirements. |
Derivative Instruments (Detai_3
Derivative Instruments (Details 3) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on Sale of Derivatives | [1],[2] | $ 256 | $ 193 | $ 7 |
Unrealized Gain (Loss) on Derivatives | [3] | 275 | (205) | (169) |
Gain (Loss) on Derivative Instruments, Net, Pretax | [4] | 531 | (12) | (162) |
Energy Related Derivative [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on Sale of Derivatives | [1],[2] | 256 | 193 | 7 |
Unrealized Gain (Loss) on Derivatives | [3] | 278 | (208) | (171) |
Interest Rate Contract [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized Gain (Loss) on Derivatives | [3] | (3) | 3 | 2 |
Sales [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on Derivative Instruments, Net, Pretax | [4],[5],[6] | 816 | (369) | (69) |
Cost of Sales [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on Derivative Instruments, Net, Pretax | [4],[5],[6] | (282) | 354 | (95) |
Interest Expense [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on Derivative Instruments, Net, Pretax | $ (3) | $ 3 | $ 2 | |
[1] | Does not include the realized value associated with derivative instruments that settle through physical delivery. | |||
[2] | Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions | |||
[3] | In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure. | |||
[4] | In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure. | |||
[5] | Does not include the realized value associated with derivative instruments that settle through physical delivery. | |||
[6] | Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions |
Derivative Instruments (Detai_4
Derivative Instruments (Details 4) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss) | $ (2) | $ (6) | $ (48) | |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax | (40) | 46 | 26 | |
Interest Rate Contract [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax | [1],[2] | (41) | 45 | 21 |
Depreciation expense [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax | [1],[2] | 1 | 1 | 5 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss) | (2) | (6) | (48) | |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Contract [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss) | [1],[2],[3],[4] | (1) | (5) | (43) |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Depreciation expense [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss) | [1],[2],[3],[4] | $ (1) | $ (1) | $ (5) |
[1] | We recorded a gain of $1 million on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the years ended December 31, 2018 and 2017. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings. | |||
[2] | We recorded an income tax benefit of $2 million and income tax expense of $5 million and $6 million for the years ended December 31, 2019, 2018 and 2017, respectively, in AOCI related to our cash flow hedging activities. | |||
[3] | Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $72 million, $34 million and $72 million at December 31, 2019, 2018 and 2017, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million, $3 million and $6 million at December 31, 2019, 2018 and 2017, respectively. | |||
[4] | Includes losses of $2 million, $1 million and nil that were reclassified from AOCI to interest expense for the years ended December 31, 2019, 2018 and 2017, respectively, where the hedged transactions became probable of not occurring. |
Derivative Instruments (Detail
Derivative Instruments (Detail 5) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |||
Derivative [Line Items] | |||||
Derivative, Collateral, Right to Reclaim Cash | $ 191 | $ 244 | |||
Net derivative assets (liabilities) | [1] | 114 | (141) | ||
Derivative Asset, Current | [1] | 156 | [2] | 142 | [3] |
Derivative Asset, Noncurrent | [1] | 246 | [2] | 160 | [3] |
Derivative Asset | [1] | 402 | 302 | ||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | 0 | 188 | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 114 | 47 | |||
Derivative Liability, Current | [1] | (225) | [2] | (303) | [3] |
Derivative Liability, Noncurrent | [1] | (63) | [2] | (140) | [3] |
Derivative Liability | [1] | (288) | (443) | ||
Future [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Current | [1] | 0 | 0 | ||
Derivative Asset, Noncurrent | [1] | 0 | 0 | ||
Derivative Asset | 872 | 933 | |||
Derivative Liability, Current | [1] | 0 | 0 | ||
Derivative Liability, Noncurrent | [1] | 0 | 0 | ||
Derivative Liability | (984) | (932) | |||
Interest Rate Contract [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Current | [1] | 2 | 30 | ||
Derivative Asset, Noncurrent | [1] | 10 | 10 | ||
Derivative Asset | 12 | 40 | |||
Derivative Liability, Current | [1] | (13) | (4) | ||
Derivative Liability, Noncurrent | [1] | (18) | (6) | ||
Derivative Liability | (31) | (10) | |||
Forward Contracts [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Current | [1] | 154 | 112 | ||
Derivative Asset, Noncurrent | [1] | 236 | 150 | ||
Derivative Asset | [4] | 539 | 550 | ||
Derivative Liability, Current | [1] | (212) | (299) | ||
Derivative Liability, Noncurrent | [1] | (45) | (134) | ||
Derivative Liability | [4] | (408) | (769) | ||
Derivative Assets, Current [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 991 | [2] | 1,191 | [3] | |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (835) | [2] | (1,049) | [3] | |
Derivative Assets, Current [Member] | Future [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 727 | 820 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (727) | (820) | |||
Derivative Assets, Current [Member] | Interest Rate Contract [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 2 | 30 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 0 | 0 | |||
Derivative Assets, Current [Member] | Forward Contracts [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 262 | 341 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (108) | (229) | |||
Derivative Assets, Non-current [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 432 | [2] | 332 | [3] | |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (186) | [2] | (172) | [3] | |
Derivative Assets, Non-current [Member] | Future [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 145 | 113 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (145) | (113) | |||
Derivative Assets, Non-current [Member] | Interest Rate Contract [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 10 | 10 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 0 | 0 | |||
Derivative Assets, Non-current [Member] | Forward Contracts [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 277 | 209 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (41) | (59) | |||
Derivative Liabilities, Current [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (1,164) | [2] | (1,344) | [3] | |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 939 | [2] | 1,041 | [3] | |
Derivative Liabilities, Current [Member] | Future [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (830) | (764) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 830 | 764 | |||
Derivative Liabilities, Current [Member] | Interest Rate Contract [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (13) | (4) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 0 | 0 | |||
Derivative Liabilities, Current [Member] | Forward Contracts [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (321) | (576) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 109 | 277 | |||
Derivative Liabilities, Non-current [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (259) | [2] | (367) | [3] | |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 196 | [2] | 227 | [3] | |
Derivative Liabilities, Non-current [Member] | Future [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (154) | (168) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 154 | 168 | |||
Derivative Liabilities, Non-current [Member] | Interest Rate Contract [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (18) | (6) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 0 | 0 | |||
Derivative Liabilities, Non-current [Member] | Forward Contracts [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (87) | (193) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 42 | 59 | |||
Derivative Financial Instruments, Assets [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 1,423 | 1,523 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (1,021) | (1,221) | |||
Derivative Financial Instruments, Liabilities [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (1,423) | (1,711) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | $ 1,135 | $ 1,268 | |||
[1] | At December 31, 2019 and 2018, we had $191 million and $244 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Balance Sheets primarily related to initial margin requirements. | ||||
[2] | At December 31, 2019, current and long-term derivative assets are shown net of collateral of $(4) million and $(4) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $108 million and $14 million, respectively. | ||||
[3] | At December 31, 2018, current and long-term derivative assets are shown net of collateral of $(58) million and $(8) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $49 million and $64 million, respectively. | ||||
[4] | Includes OTC swaps and options. |
Derivative Instruments (Textual
Derivative Instruments (Textuals) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Derivatives, Fair Value [Line Items] | |||
Derivative, Collateral, Right to Reclaim Cash | $ 191 | $ 244 | |
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 1 | $ 1 | |
Maximum length of time hedging using interest rate derivative instruments | 6 years | ||
Derivative, Net Liability Position, Aggregate Fair Value | $ 153 | ||
Collateral Already Posted, Aggregate Fair Value | 93 | ||
Additional Collateral, Aggregate Fair Value | 3 | ||
Other Comprehensive Income Loss Derivatives Qualifying As Hedges Tax | 2 | 5 | 6 |
(Gain) Loss on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net | 2 | 1 | 0 |
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | (26) | ||
Collateral Offset in Current Derivatives Assets | (4) | (58) | |
Collateral Offset in Long-Term Derivative Assets | (4) | (8) | |
Collateral Offset in Current Derivative Liabilities | 108 | 49 | |
Collateral Offset in Long-term Derivative Liabilities | 14 | 64 | |
Parent [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | (72) | (34) | (72) |
Noncontrolling Interest [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | $ (3) | $ (3) | $ (6) |
Use of Collateral (Details)
Use of Collateral (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Financial Instruments Owned and Pledged as Collateral [Line Items] | |||
Margin Deposit Assets | [1] | $ 432 | $ 343 |
Natural gas and power prepayments | 29 | 31 | |
Total margin deposits and natural gas and power prepayments with our counterparties | [2] | 461 | 374 |
Letters of credit issued | 906 | 1,166 | |
First priority liens under power and natural gas agreements | 42 | 92 | |
First priority liens under interest rate hedging instruments | 31 | 10 | |
Letters of Credit Issued and First Priority Liens Under Power Natural Gas And Interest Rate Hedging Instruments | 979 | 1,268 | |
Margin deposits posted with us by our counterparties | [1],[3] | 127 | 52 |
Letters of credit posted with us by our counterparties | 25 | 27 | |
Total margin deposits and letters of credit posted with us by our counterparties | 152 | 79 | |
Prepaid Expenses and Other Current Assets [Member] | |||
Financial Instruments Owned and Pledged as Collateral [Line Items] | |||
Total margin deposits and natural gas and power prepayments with our counterparties | 336 | 286 | |
Other Assets [Member] | |||
Financial Instruments Owned and Pledged as Collateral [Line Items] | |||
Total margin deposits and natural gas and power prepayments with our counterparties | 8 | 9 | |
Current and Non-current Derivative Assets and Liabilities [Member] | |||
Financial Instruments Owned and Pledged as Collateral [Line Items] | |||
Total margin deposits and natural gas and power prepayments with our counterparties | 117 | 79 | |
Margin deposits posted with us by our counterparties | 3 | 32 | |
Other Current Liabilities [Member] | |||
Financial Instruments Owned and Pledged as Collateral [Line Items] | |||
Margin deposits posted with us by our counterparties | 93 | 20 | |
Other Noncurrent Liabilities [Member] | |||
Financial Instruments Owned and Pledged as Collateral [Line Items] | |||
Margin deposits posted with us by our counterparties | $ 31 | $ 0 | |
[1] | We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 10 for further discussion of our derivative instruments subject to master netting arrangements. | ||
[2] | At December 31, 2019 and 2018, $117 million and $79 million, respectively, were included in current and long-term derivative assets and liabilities, $336 million and $286 million, respectively, were included in margin deposits and other prepaid expense and $8 million and $9 million, respectively, were included in other assets on our Consolidated Balance Sheets. | ||
[3] | At December 31, 2019 and 2018, $3 million and $32 million, respectively, were included in current and long-term derivative assets and liabilities, $93 million and $20 million, respectively, were included in other current liabilities and $31 million and nil, respectively, were included in other long-term liabilities on our Consolidated Balance Sheets. |
Income Taxes (Income Tax Expens
Income Taxes (Income Tax Expense (Benefit)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | $ 127 | ||
U.S. | 836 | $ 47 | $ (358) |
International | 32 | 27 | 27 |
Total | $ 868 | $ 74 | $ (331) |
Income Taxes (Components of Inc
Income Taxes (Components of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Federal | $ (2) | $ 0 | $ (10) |
State | 2 | 20 | 18 |
Foreign | 3 | (3) | (14) |
Total current | 3 | 17 | (6) |
Federal | 66 | (1) | 5 |
State | 28 | (6) | 6 |
Foreign | 1 | 54 | 3 |
Total deferred | 95 | 47 | 14 |
Total income tax expense (benefit) | $ 98 | $ 64 | $ 8 |
Income Taxes (Effective Income
Income Taxes (Effective Income Tax Expense (Benefit) Rate) (Details) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax [Line Items] | |||
Federal statutory tax expense (benefit) rate | 21.00% | 21.00% | 35.00% |
State tax expense (benefit), net of federal benefit | 2.80% | 17.00% | (6.00%) |
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | 0.00% | 0.00% | (168.80%) |
Effective Income Tax Rate Reconciliation Change in Deferred Tax Assets, Valuation Allowance Due to Tax Rate Change | 0.00% | 0.00% | 168.80% |
Valuation allowances | (11.20%) | (31.70%) | (33.00%) |
Effective Income Tax Rate Reconciliation Change in Deferred Tax Assets, Valuation Allowance Due to Foreign Taxes | 0.00% | (138.30%) | 0.50% |
Effective Income Tax Rate Reconciliation, Decrease in foreign NOL Due to Change In Ownership | 0.00% | 202.30% | 0.00% |
Foreign taxes | 0.20% | 6.60% | (2.00%) |
Change in unrecognized tax benefits | 0.00% | (8.00%) | 5.10% |
Effective Income Tax Rate Reconciliation Nondeductible Expense Disallowed Compensation | 0.00% | 7.70% | (0.60%) |
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Payment Arrangement, Percent | 0.00% | (1.50%) | (0.90%) |
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Other, Percent | 0.10% | 1.40% | (0.80%) |
Effective Tax Rate Reconciliation, Merger Related Fees/Expense | 0.00% | 12.70% | 0.00% |
Effective Income Tax Rate Reconciliation, Depletion In Excess Of Basis | (0.30%) | (4.00%) | 0.00% |
Permanent differences and other items | (1.30%) | 1.30% | 0.30% |
Effective income tax expense (benefit) rate | 11.30% | 86.50% | (2.40%) |
Income Taxes (Deferred Tax Asse
Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Valuation Allowance [Line Items] | |||
Income Tax Expense (Benefit), Intraperiod Tax Allocation | $ 0 | $ 1 | $ 6 |
NOL and credit carryforwards | 1,731 | 1,595 | |
Taxes related to risk management activities and derivatives | 18 | 7 | |
Reorganization items and impairments | 73 | 166 | |
Deferred Tax Assets, Other | 62 | 101 | |
Deferred tax assets before valuation allowance | 1,884 | 1,869 | |
Valuation allowance | (873) | (1,000) | |
Valuation Allowance, Deferred Tax Asset, Change in Amount | 127 | ||
Total deferred tax assets | 1,011 | 869 | |
Deferred tax liabilities: property, plant and equipment | (1,125) | (890) | |
Deferred Tax Liabilities, Gross | (1,125) | (890) | |
Deferred Tax Liabilities, Net | 114 | ||
Deferred Tax Assets, Net | 21 | ||
Deferred Tax Liabilities, Gross, Noncurrent | (116) | (22) | |
Deferred Tax Assets, Gross, Noncurrent | $ 2 | 1 | |
Change in Valuation due to Merger [Member] | |||
Valuation Allowance [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | $ (58) |
Income Taxes (Income Tax Contin
Income Taxes (Income Tax Contingencies) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Balance, beginning of period | $ (28) | $ (38) | $ (59) |
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions | 0 | 7 | 0 |
Decreases related to prior year tax positions | 0 | 17 | 11 |
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions | (1) | 0 | (2) |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 0 | 0 | 12 |
Balance, end of period | $ (29) | $ (28) | $ (38) |
Income Taxes (Textuals) (Detail
Income Taxes (Textuals) (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Intraperiod income tax [Line Items] | ||||
Number of States for NOL Carryforwards | 25 | |||
Federal statutory tax expense (benefit) rate | 21.00% | 21.00% | 35.00% | |
Income Tax Disclosure (Textuals) [Abstract] | ||||
Unrecognized Tax Benefits | $ 29 | $ 28 | $ 38 | $ 59 |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 17 | |||
Unrecognized Tax Benefits Resulting in Net Operating Loss Carryforward | 12 | |||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | 3 | 2 | ||
Valuation allowance | 873 | 1,000 | ||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 127 | |||
Deferred Tax Assets, Net of Valuation Allowance | 1,011 | 869 | ||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense | 1 | (2) | $ (8) | |
Expiration date 2024 through 2037 [Member] | ||||
Intraperiod income tax [Line Items] | ||||
Deferred Tax Assets, Operating Loss Carryforwards, Domestic | 7,100 | |||
Expiration date 2020 through 2039 [Member] | ||||
Income Tax Disclosure (Textuals) [Abstract] | ||||
Deferred Tax Assets, Operating Loss Carryforwards, State and Local | $ 3,200 | |||
Change in Valuation due to Merger [Member] | ||||
Income Tax Disclosure (Textuals) [Abstract] | ||||
Valuation Allowance, Deferred Tax Asset, Change in Amount | $ (58) |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 08, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Sale of Stock, Price Per Share | $ 15.25 | |||
Payments for Repurchase of Common Stock | $ 0 | $ 79 | $ 0 | |
Share-based Payment Arrangement, Accelerated Cost | 35 | |||
Stock-based compensation expense | 41 | 36 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value | 11 | 0 | ||
Option exercises | 0 | 0 | ||
Restricted Stock [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value | 88 | 23 | ||
Performance Shares [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid | 25 | |||
Share-based Compensation Arrangement by Liability Classified Share-based Payment Awards Accelerated Compensation Cost | 16 | |||
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards | $ 16 | $ 6 |
Defined Contribution and Defi_2
Defined Contribution and Defined Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Contribution and Defined Benefit Plans [Abstract] | |||
Defined Contribution Plan, Cost | $ 20 | $ 20 | $ 14 |
Employer Matching Contribution Percentage | 100.00% | ||
Deferral Election Percentage For Employer Matching Contribution | 5.00% | ||
Employee Deferral Limit Percentage | 75.00% | ||
Defined Benefit Pension Plan, Percent of Eligible Participants | 4.00% | ||
Assets for Plan Benefits, Defined Benefit Plan | $ 26 | 19 | |
Liability, Defined Benefit Plan | 33 | 27 | |
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position | 7 | 8 | |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) | 1 | 1 | $ 1 |
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | 6 | 4 | |
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year | 4 | $ 1 | |
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year | 0 | ||
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | $ 1 |
Capital Structure (Details)
Capital Structure (Details) - USD ($) $ / shares in Units, $ in Billions | 3 Months Ended | 12 Months Ended | ||||
Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 08, 2018 | Dec. 31, 2016 | |
Class of Stock [Line Items] | ||||||
Sale of Stock, Price Per Share | $ 15.25 | |||||
Sale of Stock, Consideration Received on Transaction | $ 5.6 | |||||
Common Stock, authorized shares (in shares) | 5,000 | 5,000 | ||||
Common Stock, issued shares (in shares) | 105.2 | 105.2 | ||||
Treasury Stock, Shares | ||||||
Common Stock, par value (in dollars per share) | $ 0.001 | $ 0.001 | ||||
Common Stock, outstanding shares (in shares) | 105.2 | 105.2 | 360,516,091 | 359,061,764 | ||
Shares issued under Calpine Equity Incentive Plans | 0 | (121,906) | 1,454,327 | |||
Stock Canceled During the Period, Shares | (360,394,185) | |||||
Stock Issued During Period, Shares, New Issues | 105.2 | |||||
Shares Issued [Member] | ||||||
Class of Stock [Line Items] | ||||||
Common Stock, issued shares (in shares) | 105.2 | 105.2 | 361,677,891 | 359,627,113 | ||
Shares issued under Calpine Equity Incentive Plans | 0 | 355,805 | 2,050,778 | |||
Stock Canceled During the Period, Shares | (362,033,696) | |||||
Stock Issued During Period, Shares, New Issues | 105.2 | |||||
Treasury Stock [Member] | ||||||
Class of Stock [Line Items] | ||||||
Treasury Stock, Shares | 0 | 0 | 1,161,800 | 565,349 | ||
Shares issued under Calpine Equity Incentive Plans | 0 | (477,711) | (596,451) | |||
Stock Canceled During the Period, Shares | 1,639,511 | |||||
Stock Issued During Period, Shares, New Issues | 0 |
Commitments and Contingencies_2
Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Other Commitments [Line Items] | ||||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | [1] | $ 50 | ||
Royalty Expense | $ 24 | 26 | $ 25 | |
Guarantor Obligations, Current Carrying Value | 0 | |||
Unrecorded Unconditional Purchase Obligation | ||||
Operating Leases, Future Minimum Payments, Due in Two Years | [1] | 19 | ||
Operating Leases, Future Minimum Payments, Due in Three Years | [1] | 20 | ||
Operating Leases, Future Minimum Payments, Due in Four Years | [1] | 18 | ||
Operating Leases, Future Minimum Payments, Due in Five Years | [1] | 17 | ||
Operating Leases, Future Minimum Payments, Due Thereafter | [1] | 192 | ||
Operating Leases, Future Minimum Payments Due | [1] | $ 316 | ||
LTSA [Member] | ||||
Unrecorded Unconditional Purchase Obligation | ||||
Unrecorded Unconditional Purchase Obligation | $ 217 | |||
Minimum [Member] | LTSA [Member] | ||||
Unrecorded Unconditional Purchase Obligation | ||||
Unrecorded Unconditional Purchase Obligation, Term | 1 year | |||
Maximum [Member] | LTSA [Member] | ||||
Unrecorded Unconditional Purchase Obligation | ||||
Unrecorded Unconditional Purchase Obligation, Term | 20 years | |||
[1] | During the years ended December 31, 2018 and 2017, expense for operating leases amounted to $53 million and $50 million, respectively. |
Commitments and Contingencies_3
Commitments and Contingencies (Schedules of Future Minimum Rental Payments) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Operating Leased Assets [Line Items] | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | [1] | $ 50 | |
Operating Leases, Future Minimum Payments, Due in Two Years | [1] | 19 | |
Operating Leases, Future Minimum Payments, Due in Three Years | [1] | 20 | |
Operating Leases, Future Minimum Payments, Due in Four Years | [1] | 18 | |
Operating Leases, Future Minimum Payments, Due in Five Years | [1] | 17 | |
Operating Leases, Future Minimum Payments, Due Thereafter | [1] | 192 | |
Operating Leases, Future Minimum Payments Due | [1] | $ 316 | |
Natural Gas [Member] | |||
Operating Leased Assets [Line Items] | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | $ 402 | ||
Operating Leases, Future Minimum Payments, Due in Two Years | 178 | ||
Operating Leases, Future Minimum Payments, Due in Three Years | 121 | ||
Operating Leases, Future Minimum Payments, Due in Four Years | 98 | ||
Operating Leases, Future Minimum Payments, Due in Five Years | 41 | ||
Operating Leases, Future Minimum Payments, Due Thereafter | 103 | ||
Operating Leases, Future Minimum Payments Due | $ 943 | ||
[1] | During the years ended December 31, 2018 and 2017, expense for operating leases amounted to $53 million and $50 million, respectively. |
Commitments and Contingencies_4
Commitments and Contingencies (Schedule of Guarantor Obligations) (Details) $ in Millions | Dec. 31, 2019USD ($) | |
Loans Payable [Member] | ||
Guarantor Obligations [Line Items] | ||
Guarantee Obligations Balance On First Anniversary | $ 30 | [1] |
Guarantee Obligations Balance On Second Anniversary | 29 | [1] |
Guarantee Obligations Balance On Third Anniversary | 24 | [1] |
Guarantee Obligations Balance On Fourth Anniversary | 14 | [1] |
Guarantee Obligations Balance On Fifth Anniversary | 13 | [1] |
Guarantee Obligations Due After Five Years | 39 | [1] |
Guarantor Obligations, Maximum Exposure, Undiscounted | 149 | [1] |
Financial Standby Letter of Credit [Member] | ||
Guarantor Obligations [Line Items] | ||
Guarantee Obligations Balance On First Anniversary | 1,015 | [2],[3],[4] |
Guarantee Obligations Balance On Second Anniversary | 32 | [2],[3],[4] |
Guarantee Obligations Balance On Third Anniversary | 0 | [2],[3],[4] |
Guarantee Obligations Balance On Fourth Anniversary | 38 | [2],[3],[4] |
Guarantee Obligations Balance On Fifth Anniversary | 0 | [2],[3],[4] |
Guarantee Obligations Due After Five Years | 0 | [2],[3],[4] |
Guarantor Obligations, Maximum Exposure, Undiscounted | 1,085 | [2],[3],[4] |
Surety Bonds [Member] | ||
Guarantor Obligations [Line Items] | ||
Guarantee Obligations Balance On First Anniversary | 10 | [4],[5],[6] |
Guarantee Obligations Balance On Second Anniversary | 7 | [4],[5],[6] |
Guarantee Obligations Balance On Third Anniversary | 0 | [4],[5],[6] |
Guarantee Obligations Balance On Fourth Anniversary | 0 | [4],[5],[6] |
Guarantee Obligations Balance On Fifth Anniversary | 0 | [4],[5],[6] |
Guarantee Obligations Due After Five Years | 94 | [4],[5],[6] |
Guarantor Obligations, Maximum Exposure, Undiscounted | 111 | [4],[5],[6] |
Accounts Receivable Sales Program [Member] | ||
Guarantor Obligations [Line Items] | ||
Guarantee Obligations Balance On First Anniversary | 222 | [7] |
Guarantee Obligations Balance On Second Anniversary | 0 | [7] |
Guarantee Obligations Balance On Third Anniversary | 0 | [7] |
Guarantee Obligations Balance On Fourth Anniversary | 0 | [7] |
Guarantee Obligations Balance On Fifth Anniversary | 0 | [7] |
Guarantee Obligations Due After Five Years | 0 | [7] |
Guarantor Obligations, Maximum Exposure, Undiscounted | 222 | [7] |
Gurantee Obligations Total [Member] | ||
Guarantor Obligations [Line Items] | ||
Guarantee Obligations Balance On First Anniversary | 1,277 | |
Guarantee Obligations Balance On Second Anniversary | 68 | |
Guarantee Obligations Balance On Third Anniversary | 24 | |
Guarantee Obligations Balance On Fourth Anniversary | 52 | |
Guarantee Obligations Balance On Fifth Anniversary | 13 | |
Guarantee Obligations Due After Five Years | 133 | |
Guarantor Obligations, Maximum Exposure, Undiscounted | $ 1,567 | |
[1] | Represents Calpine Corporation guarantees of certain power plant leases and related interest. All guaranteed finance leases are recorded on our Consolidated Balance Sheets. | |
[2] | Letters of credit are renewed annually and as such all amounts are reflected in the year of letter of credit expiration. The related commercial obligations extend for multiple years, therefore, renewal of the letter of credit will likely follow the term of the associated commercial obligation. | |
[3] | The standby letters of credit disclosed above represent those disclosed in Note 8. | |
[4] | These are contingent off balance sheet obligations. | |
[5] | As of December 31, 2019, no cash collateral is outstanding related to these bonds. | |
[6] | The majority of surety bonds do not have expiration or cancellation dates. | |
[7] | Calpine has guaranteed the performance of Calpine Solutions under the Accounts Receivable Sales Program. The Accounts Receivable Sales Program expires on November 27, 2020. |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |||
Sale of Accounts Receivables Current Facility | $ 250 | ||
Percentage of Accounts Receivables Sold to Third Party | 100.00% | ||
Continuing Involvement with Derecognized Transferred Financial Assets, Amount Outstanding | $ 222 | $ 238 | |
Notes Receivable, Related Parties, Current | 38 | 34 | |
Trade Receivables Sold | 2,300 | 2,400 | $ 2,200 |
Cash Flows Between Transferor and Transferee, Proceeds from New Transfers | 2,300 | 2,300 | $ 2,200 |
Revenue from Related Parties | 70 | 76 | |
Related Party Transaction, Purchases from Related Party | $ 14 | $ 12 |
Segment and Significant Custo_3
Segment and Significant Customer Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | $ 2,082 | $ 2,792 | $ 2,599 | $ 2,599 | $ 2,354 | $ 2,890 | $ 2,259 | $ 2,009 | $ 10,072 | [1] | $ 9,512 | [1] | $ 8,752 | [1] | |
Commodity Margin | 3,314 | 3,033 | 2,708 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | [2] | 254 | (270) | (294) | |||||||||||
Operating and maintenance expense | 1,001 | 1,020 | 1,080 | ||||||||||||
Depreciation and amortization expense | 694 | 739 | 724 | ||||||||||||
General and other administrative expense | 150 | 158 | 155 | ||||||||||||
Other Cost and Expense, Operating | 79 | 98 | 85 | ||||||||||||
Impairment losses | 84 | 10 | 41 | ||||||||||||
(Gain) on sale of assets, net | (10) | 0 | (27) | ||||||||||||
(Income) from unconsolidated subsidiaries | 22 | 24 | 22 | ||||||||||||
Income from operations | $ 108 | $ 682 | $ 444 | $ 358 | $ 105 | $ 568 | $ 417 | $ (328) | 1,592 | 762 | 378 | ||||
Interest expense, net of interest income | 609 | 617 | 621 | ||||||||||||
Debt Extinguishment Costs and Other (Income) Expense, Net | 95 | 53 | 70 | ||||||||||||
Income before income taxes | 888 | 92 | (313) | ||||||||||||
Lease levelization | 1 | 0 | (8) | ||||||||||||
Contract amortization | $ 72 | $ 100 | $ 175 | ||||||||||||
Number of significant customers | 0 | 0 | 0 | ||||||||||||
West [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | [1] | $ 2,743 | $ 1,988 | $ 1,881 | |||||||||||
Commodity Margin | 1,151 | 1,060 | 970 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | [2] | 219 | (165) | (19) | |||||||||||
Operating and maintenance expense | 340 | 348 | 361 | ||||||||||||
Depreciation and amortization expense | 254 | 269 | 240 | ||||||||||||
General and other administrative expense | 35 | 40 | 45 | ||||||||||||
Other Cost and Expense, Operating | 31 | 42 | 38 | ||||||||||||
Impairment losses | 0 | 0 | 28 | ||||||||||||
(Gain) on sale of assets, net | (4) | 0 | |||||||||||||
(Income) from unconsolidated subsidiaries | 0 | 0 | 0 | ||||||||||||
Income from operations | 714 | 196 | 239 | ||||||||||||
Texas [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | [1] | 3,081 | 2,860 | 2,342 | |||||||||||
Commodity Margin | 857 | 646 | 552 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | [2] | 154 | (197) | (174) | |||||||||||
Operating and maintenance expense | 269 | 272 | 308 | ||||||||||||
Depreciation and amortization expense | 196 | 237 | 208 | ||||||||||||
General and other administrative expense | 53 | 61 | 66 | ||||||||||||
Other Cost and Expense, Operating | 6 | 24 | 14 | ||||||||||||
Impairment losses | 13 | 0 | 13 | ||||||||||||
(Gain) on sale of assets, net | 0 | 0 | |||||||||||||
(Income) from unconsolidated subsidiaries | 0 | 0 | 0 | ||||||||||||
Income from operations | 474 | (145) | (231) | ||||||||||||
East [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | [1] | 2,164 | 1,987 | 1,658 | |||||||||||
Commodity Margin | 924 | 970 | 790 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | [2] | 46 | 40 | (62) | |||||||||||
Operating and maintenance expense | 278 | 269 | 302 | ||||||||||||
Depreciation and amortization expense | 191 | 180 | 201 | ||||||||||||
General and other administrative expense | 45 | 38 | 27 | ||||||||||||
Other Cost and Expense, Operating | 42 | 32 | 33 | ||||||||||||
Impairment losses | 71 | 10 | 0 | ||||||||||||
(Gain) on sale of assets, net | (6) | (27) | |||||||||||||
(Income) from unconsolidated subsidiaries | 24 | 26 | 24 | ||||||||||||
Income from operations | 373 | 507 | 216 | ||||||||||||
Consolidation, Eliminations [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | [1] | (2,009) | (1,299) | (926) | |||||||||||
Commodity Margin | 0 | 0 | 0 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | (34) | [2] | (32) | (29) | |||||||||||
Operating and maintenance expense | (34) | (32) | (29) | ||||||||||||
Depreciation and amortization expense | 0 | 0 | 0 | ||||||||||||
General and other administrative expense | 0 | 0 | 0 | ||||||||||||
Other Cost and Expense, Operating | 0 | 0 | 0 | ||||||||||||
Impairment losses | 0 | 0 | 0 | ||||||||||||
(Gain) on sale of assets, net | 0 | 0 | |||||||||||||
(Income) from unconsolidated subsidiaries | 0 | 0 | 0 | ||||||||||||
Income from operations | 0 | 0 | 0 | ||||||||||||
Retail [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | [1] | 4,093 | 3,976 | 3,797 | |||||||||||
Commodity Margin | 382 | 357 | 396 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | (131) | [2] | 84 | (10) | |||||||||||
Operating and maintenance expense | 148 | 163 | 138 | ||||||||||||
Depreciation and amortization expense | 53 | 53 | 75 | ||||||||||||
General and other administrative expense | 17 | 19 | 17 | ||||||||||||
Other Cost and Expense, Operating | 0 | 0 | 0 | ||||||||||||
Impairment losses | 0 | 0 | 0 | ||||||||||||
(Gain) on sale of assets, net | 0 | 0 | |||||||||||||
(Income) from unconsolidated subsidiaries | (2) | (2) | (2) | ||||||||||||
Income from operations | 31 | 204 | 154 | ||||||||||||
Intersegment Eliminations [Member] | West [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | 530 | 488 | 324 | ||||||||||||
Intersegment Eliminations [Member] | Texas [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | 946 | 573 | 361 | ||||||||||||
Intersegment Eliminations [Member] | East [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | 522 | 234 | 237 | ||||||||||||
Intersegment Eliminations [Member] | Retail [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | 11 | 4 | 4 | ||||||||||||
Other Assets [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Contract amortization | $ 78 | $ 104 | $ 178 | ||||||||||||
[1] | Includes intersegment revenues of $530 million, $488 million and $324 million in the West, $946 million, $573 million and $361 million in Texas, $522 million, $234 million and $237 million in the East and $11 million, $4 million, $4 million in Retail for the years ended December 31, 2019, 2018 and 2017, respectively. | ||||||||||||||
[2] | Includes $1 million, nil and $(8) million of lease levelization and $78 million, $104 million and $178 million of amortization expense for the years ended December 31, 2019, 2018 and 2017, respectively. |
Quarterly Consolidated Financ_3
Quarterly Consolidated Financial Data (unaudited) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||
Operating revenues | $ 2,082 | $ 2,792 | $ 2,599 | $ 2,599 | $ 2,354 | $ 2,890 | $ 2,259 | $ 2,009 | $ 10,072 | [1] | $ 9,512 | [1] | $ 8,752 | [1] |
Income (loss) from operations | 108 | 682 | 444 | 358 | 105 | 568 | 417 | (328) | 1,592 | 762 | 378 | |||
Net income (loss) attributable to Calpine | $ (156) | $ 485 | $ 266 | $ 175 | $ (16) | $ 272 | $ 352 | $ (598) | $ 770 | $ 10 | $ (339) | |||
[1] | Includes intersegment revenues of $530 million, $488 million and $324 million in the West, $946 million, $573 million and $361 million in Texas, $522 million, $234 million and $237 million in the East and $11 million, $4 million, $4 million in Retail for the years ended December 31, 2019, 2018 and 2017, respectively. |
Schedule of Valuation and Qua_2
Schedule of Valuation and Qualifying Accounts Disclosure (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
SEC Schedule, 12-09, Allowance, Credit Loss [Member] | ||||
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | ||||
Balance at Beginning of Year | $ 9 | $ 9 | $ 6 | |
Charged to Expense | (6) | (5) | (4) | |
Charged to Other Accounts | (1) | 1 | 2 | |
Deductions | [1] | (5) | (6) | (3) |
Balance at End of Year | 9 | 9 | 9 | |
Deferred Tax Asset Valuation Allowance [Member] | ||||
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | ||||
Balance at Beginning of Year | 1,000 | 1,168 | 1,581 | |
Charged to Expense | (127) | (168) | (413) | |
Charged to Other Accounts | 0 | 0 | 0 | |
Deductions | [1] | 0 | 0 | 0 |
Balance at End of Year | $ 873 | $ 1,000 | $ 1,168 | |
[1] | Represents write-offs of accounts considered to be uncollectible and previously reserved. |