Document and Entity Information
Document and Entity Information Cover - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Mar. 28, 2019 | Jun. 30, 2018 | |
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, 2018 | ||
Document Fiscal Year Focus | 2018 | ||
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Operating revenues: | ||||
Commodity revenue | $ 9,865 | $ 8,836 | $ 6,943 | |
Mark to Market Gain Loss on Derivatives included in Operating Revenues | (373) | (101) | (245) | |
Other revenue | 20 | 17 | 18 | |
Operating revenues | [1] | 9,512 | 8,752 | 6,716 |
Operating expenses: | ||||
Commodity expense | 6,914 | 6,268 | 4,431 | |
Mark to Market Gain Loss on Derivatives Included in Fuel and Purchased Energy Expense | (165) | 70 | (244) | |
Fuel and purchased energy expense | 6,749 | 6,338 | 4,187 | |
Operating and maintenance expense | 1,020 | 1,080 | 977 | |
Depreciation and amortization expense | 739 | 724 | 662 | |
General and other administrative expense | 158 | 155 | 140 | |
Other operating expenses | 98 | 85 | 79 | |
Total operating expenses | 8,764 | 8,382 | 6,045 | |
Impairment losses | 10 | 41 | 13 | |
(Gain) on sale of assets, net | 0 | (27) | (157) | |
(Income) from unconsolidated subsidiaries | (24) | (22) | (24) | |
Income from operations | 762 | 378 | 839 | |
Interest expense | 617 | 621 | 631 | |
(Gain) loss on extinguishment of debt | (28) | 38 | 25 | |
Other (income) expense, net | 81 | 32 | 24 | |
Income before income taxes | 92 | (313) | 159 | |
Income tax expense | 64 | 8 | 48 | |
Net income (loss) | 28 | (321) | 111 | |
Net income attributable to the noncontrolling interest | (18) | (18) | (19) | |
Net income (loss) attributable to Calpine | $ 10 | $ (339) | $ 92 | |
[1] | Includes intersegment revenues of $488 million, $324 million and $20 million in the West, $573 million, $361 million and $81 million in Texas, $234 million, $237 million and $48 million in the East and $4 million, $4 million, $2 million in Retail for the years ended December 31, 2018, 2017 and 2016, respectively. |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Net income (loss) | $ 28 | $ (321) | $ 111 |
Cash flow hedging activities: | |||
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss) | 40 | (22) | (2) |
Reclassification adjustment for loss on cash flow hedges realized in net income (loss) | 6 | 48 | 43 |
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax | 1 | 0 | 0 |
Foreign currency translation gain (loss) | (10) | 13 | 5 |
Income tax expense | (5) | (6) | (1) |
Other comprehensive income | 32 | 33 | 45 |
Comprehensive income (loss) | 60 | (288) | 156 |
Comprehensive (income) attributable to the noncontrolling interest | (21) | (20) | (22) |
Comprehensive income (loss) attributable to Calpine | $ 39 | $ (308) | $ 134 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents ($43 and $39 attributable to VIEs) | $ 205 | $ 284 |
Accounts receivable, net of allowance of $9 and $9 | 1,022 | 970 |
Inventories | 525 | 498 |
Margin deposits and other prepaid expense | 315 | 203 |
Restricted cash, current ($90 and $74 attributable to VIEs) | 167 | 134 |
Derivative assets, current | 142 | 174 |
Other current assets | 43 | 43 |
Total current assets | 2,419 | 2,306 |
Property, plant and equipment, net ($3,919 and $4,048 attributable to VIEs) | 12,442 | 12,724 |
Restricted cash, net of current portion ($33 and $24 attributable to VIEs) | 34 | 25 |
Investments in unconsolidated subsidiaries | 76 | 106 |
Long-term derivative assets | 160 | 218 |
Goodwill | 242 | 242 |
Finite-Lived Intangible Assets, Net | 412 | 512 |
Other assets ($30 and $22 attributable to VIEs) | 277 | 320 |
Total assets | 16,062 | 16,453 |
Current liabilities: | ||
Accounts payable | 958 | 777 |
Accrued interest payable | 96 | 104 |
Debt, current portion ($201 and $175 attributable to VIEs) | 637 | 225 |
Derivative liabilities, current | 303 | 197 |
Other current liabilities | 489 | 571 |
Total current liabilities | 2,483 | 1,874 |
Debt, net of current portion ($1,978 and $2,238 attributable to VIEs) | 10,148 | 11,180 |
Long-term derivative liabilities | 140 | 119 |
Other long-term liabilities | 235 | 213 |
Total liabilities | 13,006 | 13,386 |
Stockholders’ equity: | ||
Common stock, $0.001 par value per share; authorized 5,000 and 1,400,000,000 shares, respectively, 105.2 and 361,677,891 shares issued, respectively, and 105.2 and 360,516,091 shares outstanding, respectively | 0 | 0 |
Treasury stock, at cost, nil and 1,161,800 shares, respectively | 0 | (15) |
Additional paid-in capital | 9,582 | 9,661 |
Accumulated deficit | (6,542) | (6,552) |
Accumulated other comprehensive loss | (77) | (106) |
Total Calpine stockholders’ equity | 2,963 | 2,988 |
Noncontrolling interest | 93 | 79 |
Total stockholders’ equity | 3,056 | 3,067 |
Total liabilities and stockholders’ equity | $ 16,062 | $ 16,453 |
Consolidated Balance Sheets Con
Consolidated Balance Sheets Consolidated Balance Sheets Parentheticals - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Cash and cash equivalents ($43 and $39 attributable to VIEs) | $ 205 | $ 284 |
Accounts receivable, net of allowance of $9 and $9 | 9 | 9 |
Restricted cash, current ($90 and $74 attributable to VIEs) | 167 | 134 |
Property, plant and equipment, net ($3,919 and $4,048 attributable to VIEs) | 12,442 | 12,724 |
Restricted cash, net of current portion ($33 and $24 attributable to VIEs) | 34 | 25 |
Other assets ($30 and $22 attributable to VIEs) | 277 | 320 |
Debt, current portion ($201 and $175 attributable to VIEs) | 637 | 225 |
Debt, net of current portion ($1,978 and $2,238 attributable to VIEs) | $ 10,148 | $ 11,180 |
Common Stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Common Stock, authorized shares (in shares) | 5,000 | 1,400,000,000 |
Common Stock, issued shares (in shares) | 105.2 | 361,677,891 |
Common Stock, outstanding shares (in shares) | 105.2 | 360,516,091 |
Treasury Stock, shares (in shares) | 0 | 1,161,800 |
Variable Interest Entity, Primary Beneficiary [Member] | ||
Cash and cash equivalents ($43 and $39 attributable to VIEs) | $ 43 | $ 39 |
Restricted cash, current ($90 and $74 attributable to VIEs) | 90 | 74 |
Property, plant and equipment, net ($3,919 and $4,048 attributable to VIEs) | 3,919 | 4,048 |
Restricted cash, net of current portion ($33 and $24 attributable to VIEs) | 33 | 24 |
Other assets ($30 and $22 attributable to VIEs) | 30 | 22 |
Debt, current portion ($201 and $175 attributable to VIEs) | 201 | 175 |
Debt, net of current portion ($1,978 and $2,238 attributable to VIEs) | $ 1,978 | $ 2,238 |
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, 2015 | $ 3,167 | $ 0 | $ (1) | $ 9,594 | $ (6,305) | $ (179) | $ 58 | ||
Treasury stock transactions | (6) | 0 | (6) | 0 | 0 | 0 | 0 | ||
Stock-based compensation expense | 30 | 0 | 0 | 30 | 0 | 0 | 0 | ||
Option exercises | 1 | 0 | 0 | 1 | 0 | 0 | 0 | ||
Dividends | [1] | 0 | |||||||
Distribution to the noncontrolling interest | (9) | 0 | 0 | 0 | 0 | 0 | (9) | ||
Net income (loss) | 111 | 0 | 0 | 0 | 92 | 0 | 19 | ||
Other comprehensive income (loss) | 45 | 0 | 0 | 0 | 0 | 42 | 3 | ||
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 | ||
Option exercises | 0 | ||||||||
Dividends | [1] | 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 | ||
Option exercises | 0 | ||||||||
Effects of the Merger | (78) | 0 | 22 | (100) | 0 | 0 | 0 | ||
Dividends | (20) | [1] | 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 | ||
[1] | Subsequent to the consummation of the Merger on March 8, 2018, we paid certain Merger-related costs incurred by CPN Management, our direct parent. |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||||
Cash flows from operating activities: | ||||||
Net income (loss) | $ 28 | $ (321) | $ 111 | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||
Depreciation and amortization(1) | [1] | 848 | 921 | 910 | ||
(Gain) loss on extinguishment of debt | (32) | 38 | 25 | |||
Deferred income taxes | 47 | 14 | 43 | |||
Impairment losses | 10 | 41 | 13 | |||
(Gain) on sale of assets, net | 0 | (27) | (157) | |||
Mark-to-market activity, net | [2] | 205 | 169 | (1) | ||
(Income) from unconsolidated subsidiaries | (24) | (22) | (24) | |||
Return on investments from unconsolidated subsidiaries | 35 | 28 | 21 | |||
Stock-based compensation expense | 57 | 42 | 31 | |||
Other | 29 | (5) | 8 | |||
Change in operating assets and liabilities, net of effects of acquisitions: | ||||||
Accounts receivable | (101) | (108) | (128) | |||
Accounts payable | 164 | 70 | 34 | |||
Margin deposits and other prepaid expense | (134) | 115 | 416 | |||
Other assets and liabilities, net | (82) | (15) | 19 | |||
Derivative instruments, net | 51 | 9 | (286) | |||
Net cash provided by operating activities | 1,101 | 949 | 1,035 | |||
Cash flows from investing activities: | ||||||
Purchases of property, plant and equipment | (415) | (305) | (489) | |||
Proceeds from sale of power plants and other(2) | [3] | 11 | 162 | 179 | ||
Return of investment from unconsolidated subsidiaries | 18 | 0 | 0 | |||
Other | (6) | 43 | 27 | |||
Net cash used in investing activities | (392) | (211) | (1,959) | |||
Cash flows from financing activities: | ||||||
Borrowings under CCFC Term Loan and First Lien Term Loans | 0 | 1,395 | 1,101 | |||
Repayments of CCFC Term Loans and First Lien Term Loans | (41) | (2,150) | (1,231) | |||
Borrowings under First Lien Notes | 0 | 560 | 625 | |||
Repurchases of Senior Unsecured and First Lien Notes | (355) | (453) | (120) | |||
Proceeds from Lines of Credit | 355 | 25 | 0 | |||
Repayments of Lines of Credit | (325) | (25) | 0 | |||
Borrowings from project financing, notes payable and other | 220 | 0 | 458 | |||
Repayments of project financing, notes payable and other | (470) | (174) | (364) | |||
Distribution to noncontrolling interest holder | (9) | (12) | (9) | |||
Financing costs | (18) | (60) | (63) | |||
Stock repurchases | (79) | 0 | 0 | |||
Proceeds from exercises of stock options | 0 | 0 | 1 | |||
Shares repurchased for tax withholding on stock-based awards | (7) | (7) | (6) | |||
Dividends | [4] | (20) | 0 | 0 | ||
Other | 3 | 0 | 4 | |||
Net cash (used in) provided by financing activities | (746) | (901) | 396 | |||
Net decrease in cash, cash equivalents and restricted cash | (37) | (163) | (528) | |||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 443 | [5] | 606 | [5] | 1,134 | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | [5] | 406 | 443 | 606 | ||
Cash paid during the period for: | ||||||
Interest, net of amounts capitalized | 587 | 575 | 584 | |||
Income taxes | 23 | 12 | 12 | |||
Supplemental disclosure of non-cash investing and financing activities: | ||||||
Purchase of King City Cogen Plant Lease | [6] | 0 | 15 | 0 | ||
Change in capital expenditures included in accounts payable | 19 | 20 | (37) | |||
Reduction of debt due to sale of Mankato Power Plant(2) | [3] | 0 | 0 | 243 | ||
Long-term Debt | 10,156 | 11,213 | ||||
Mankato [Member] | ||||||
Cash flows from investing activities: | ||||||
Proceeds from sale of power plants and other(2) | [3] | 407 | ||||
Supplemental disclosure of non-cash investing and financing activities: | ||||||
Proceeds from Divestiture of Businesses, Net of Cash Divested | 164 | |||||
Granite Ridge Energy Center [Member] | ||||||
Cash flows from investing activities: | ||||||
Purchase of Granite Ridge Energy Center | 0 | 0 | (526) | |||
Calpine Solutions [Member] | ||||||
Supplemental disclosure of non-cash investing and financing activities: | ||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | 800 | |||||
Working Capital Adjustment to Sale Price | 350 | |||||
Recovered collateral subsequent to closing | 250 | |||||
Calpine Solutions and Champion Energy [Member] | ||||||
Cash flows from investing activities: | ||||||
Purchase of Granite Ridge Energy Center | [7] | $ 0 | (111) | $ (1,150) | ||
King City Cogen Promissory Note [Member] | ||||||
Supplemental disclosure of non-cash investing and financing activities: | ||||||
Long-term Debt | $ 57 | |||||
[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 hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. | |||||
[3] | On October 26, 2016, we completed the sale of Mankato Power Plant for $407 million, including working capital and other adjustments. We received net proceeds of $164 million after the non-cash reduction of Steamboat project debt of $243 million as the funds were provided directly to the lender in conjunction with the sale of the power plant. | |||||
[4] | Subsequent to the consummation of the Merger on March 8, 2018, we paid certain Merger-related costs incurred by CPN Management, our direct parent. | |||||
[5] | 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 | |||||
[6] | 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. | |||||
[7] | On December 1, 2016, we completed the purchase of Calpine Solutions, formerly Noble Solutions, along with a swap contract for approximately $800 million plus approximately $350 million of net working capital at closing. We recovered approximately $250 million in cash subsequent to closing and prior to year end December 31, 2016. |
Organization and Operations
Organization and Operations | 12 Months Ended |
Dec. 31, 2018 | |
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, industrial and agricultural companies, retail power providers, municipalities 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 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 Agreement (Notes)
Merger Agreement (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Business Combination Disclosure [Text Block] | 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, 2018 and 2017, we recorded approximately $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, 2018 | |
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, Whitby, 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, 2018 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress (in millions, except percentages) Freestone Energy Center 75.0 % $ 379 $ (167 ) $ 1 Hidalgo Energy Center 78.5 % $ 251 $ (114 ) $ 4 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, 2018 and 2017 (in millions): 2018 2017 Current Non-Current Total Current Non-Current Total Debt service $ 13 $ 8 $ 21 $ 11 $ 8 $ 19 Construction/major maintenance 23 24 47 28 16 44 Security/project/insurance 120 — 120 92 — 92 Other 11 2 13 3 1 4 Total $ 167 $ 34 $ 201 $ 134 $ 25 $ 159 Business Interruption Proceeds We record business interruption insurance proceeds when they are realizable and recorded approximately $14 million , $27 million and $24 million of business interruption proceeds in operating revenues for the years ended December 31, 2018 , 2017 , and 2016 , 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 mininimis 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 during the third quarter and whenever the events or changes in circumstances indicate that the carrying value may not be recoverable. During the first quarter of 2018, we altered the composition of our segments to report the results associated with our retail business as a separate segment. This change reflects the manner in which our segment information is presented internally to our chief operating decision maker associated with the strategic utilization of our retail business subsequent to the consummation of the Merger. Thus, beginning in the first quarter of 2018, 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. As our goodwill resulted from the acquisition of our retail business over the last several years, our goodwill balance of $242 million was allocated to our Retail segment in connection with the change in segment presentation. We did not record any changes in the carrying amount of our goodwill during the year ended December 31, 2018 . During the year ended December 31, 2017 , we recorded goodwill of $49 million associated with our acquisition of North American Power and recorded $6 million in purchase price adjustments. 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 contractual rights and obligations with finite lives. As of December 31, 2018 and 2017 , the components of our intangible assets were as follows (in millions): 2018 2017 Lives Acquired contracts $ 458 $ 458 0 – 9 Years Customer relationships 445 445 7 – 14 Years Trademark and trade name 40 40 15 Years Other 88 88 17 – 23 Years 1,031 1,031 Less: Accumulated amortization 619 519 Intangible assets, net $ 412 $ 512 Amortization expense related to our intangible assets for the years ended December 31, 2018 , 2017 and 2016 was $100 million , $175 million and $218 million , respectively. The estimated aggregate amortization expense of our intangible assets for the next five years is as follows (in millions): 2019 $ 71 2020 $ 44 2021 $ 40 2022 $ 35 2023 $ 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, 2018 , 2017 and 2016 . 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 filed for protection under Chapter 11 of the U.S. Bankruptcy Code. 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 which both achieved commercial operations in 2013. As of December 31, 2018, our Consolidated Balance Sheet included net long-lived assets at Russell City Energy Center and Los Esteros Critical Energy Facility of approximately $676 million and $439 million , respectively, and non-recourse project finance debt at Russell City Energy Center and Los Esteros Critical Energy Facility of approximately $341 million and $163 million , respectively. A third party has a 25% noncontrolling interest in Russell City Energy Company, LLC, which owns and operates the Russell City Energy Center. Since the bankruptcy filing, we have received all material payments under both PPAs, either directly or through the application of collateral. 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 $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 turbine equipment in our Texas segment. We recorded impairment losses of $13 million during the year ended December 31, 2016 related to our South Point Energy Center in our West 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, 2018 and 2017 , our asset retirement obligation liabilities were $63 million and $43 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 fixed and variable capacity payments, which are not related to generation including capacity payments received from RTO and ISO capacity auctions, variable payments for power and steam, which are related to generation, retail power revenues, host steam and RECs 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 4 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. Leases — 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. We apply lease accounting to contracts that meet the definition of a lease and accrual accounting treatment to those contracts that are either exempt from derivative accounting or do not meet the definition of a derivative instrument. 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 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 purchase and sales commodity 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 Commo |
Revenue from Contracts with Cus
Revenue from Contracts with Customers (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
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 year ended December 31, 2018 by reportable segment (in millions). See Note 18 for a description of our segments. 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 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 year ended December 31, 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 year ended December 31, 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, 2018 and 2017 , 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, 2018 and 2017 , was $14 million and $15 million , respectively. The revenue recognized during the year ended December 31, 2018 , relating to the deferred revenue balance at the beginning of the period was $15 million and resulted from our performance under the customer contracts. The change in the deferred revenue balance during the year ended December 31, 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, 2018 and 2017 , the capitalized contract cost balance was not material. There were no impairment losses or changes in amortization during the year ended December 31, 2018 and amortization of contract costs during the year ended December 31, 2018 was immaterial. Performance Obligations not yet Satisfied As of December 31, 2018 , 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 $618 million , $508 million , $467 million , $201 million and $23 million that will be recognized during the years ending December 31, 2019, 2020, 2021, 2022 and 2023, respectively, and $23 million thereafter. Revenues under these contracts will be recognized as we transfer control of the commodities to our customers. |
Acquisitions, Divestitures and
Acquisitions, Divestitures and Discontinued Operations Acquisitions and Divestitures (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
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 each of the years ended December 31, 2017 and 2016 is not material. Acquisition of Calpine Solutions, formerly Noble Solutions On December 1, 2016, through our indirect, wholly-owned subsidiaries Calpine Energy Services Holdco II, LLC and Calpine Energy Financial Holdings, LLC, we completed the purchase of Calpine Solutions, formerly Noble Solutions, along with a swap contract from Noble Americas Gas & Power Corp. and Noble Group Limited for approximately $800 million plus approximately $350 million of net working capital. We recovered approximately $250 million in cash subsequent to closing and recovered an additional approximately $200 million through collateral synergies and the runoff of acquired legacy hedges, substantially within the first year. Calpine Solutions is a commercial and industrial retail electricity provider with customers in 20 states in the U.S., including presence in California, Texas, the Mid-Atlantic and Northeast, where our wholesale power generation fleet is primarily concentrated. The acquisition of this large direct energy sales platform is consistent with our stated goal of getting closer to our end-use customers and expands our retail customer base, complementing our existing retail business while providing us a valuable sales channel for reaching a much greater portion of the load we seek to serve. We funded the acquisition with a combination of cash on hand and debt financing. The results of Calpine Solutions are reflected in our Retail segment. The following table summarizes the consideration paid for Calpine Solutions as well as the preliminary determination of the identifiable assets acquired and liabilities assumed at the December 1, 2016 acquisition date (in millions): Consideration $ 1,150 Identifiable assets acquired and liabilities assumed: Assets: Current assets 141 Margin deposits and other prepaid expense 518 Derivative assets, current (1) 365 Property, plant and equipment, net 7 Intangible assets (2) 360 Goodwill 162 Long-term derivative assets (1) 359 Total assets acquired 1,912 Liabilities: Current liabilities 276 Derivative liabilities, current (1) 270 Long-term derivative liabilities (1) 216 Total liabilities assumed 762 Net assets acquired $ 1,150 ____________ (1) Consists of acquired customer and wholesale contracts which will be substantially amortized over 5 years. (2) Consists primarily of customer relationships that are being amortized over 14 years. See Note 3 for a further description of our intangible assets. We recorded goodwill of $ 162 million , all of which is deductible for tax purposes, in connection with the acquisition of Calpine Solutions which represent the excess of the purchase price over the fair values of Calpine Solution’s assets and liabilities. The goodwill acquired was allocated to our Retail segment. The purchase price allocation was finalized during the fourth quarter of 2017 which did not result in any material adjustments. The revenue and earnings of Calpine Solutions since its acquisition on December 1, 2016 are not material to our Consolidated Statements of Operations for the year ended December 31, 2016. The following table summarizes the unaudited pro forma operating revenues and net income attributable to Calpine for the periods presented as if Calpine Solutions was acquired on January 1, 2015. The unaudited pro forma information has been prepared by adding the preliminary, unaudited historical results of Calpine Solutions, as adjusted for amortization of intangible assets and acquired contracts (using the preliminary values assigned to the net assets acquired from Calpine Solutions disclosed above) and interest expense from our 2017 First Lien Term Loan which funded a portion of the purchase price, to our results for the periods indicated below (in millions). 2016 (Unaudited) Operating revenues $ 8,324 Net income attributable to Calpine $ 105 Acquisition of Granite Ridge Energy Center On February 5, 2016, we, through our indirect, wholly-owned subsidiary Calpine Granite Holdings, LLC, completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), from Granite Ridge Holdings, LLC, for approximately $500 million , excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market. Beginning operations in 2003, Granite Ridge Energy Center is located in Londonderry, New Hampshire and features two combustion turbines, two heat recovery steam generators and one steam turbine. We funded the acquisition with a combination of cash on hand and a portion of our 2023 First Lien Term Loans obtained in the fourth quarter of 2015, and the purchase price was primarily allocated to property, plant and equipment. The purchase price allocation was finalized during the first quarter of 2017 and did not result in any material adjustments or the recognition of goodwill. The pro forma incremental effect of Granite Ridge Energy Center on our results of operations for the year ended December 31, 2016 is not material. 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. Sale of Mankato Power Plant On October 26, 2016, we, through our indirect, wholly-owned subsidiaries, New Steamboat Holdings, LLC and Mankato Holdings, LLC, completed the sale of our Mankato Power Plant, a 375 MW natural gas-fired, combined-cycle power plant and 345 MW expansion project under advanced development located in Minnesota, to Southern Power Company, a subsidiary of Southern Company, for $396 million , excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. We used the proceeds from the sale to partially fund the Calpine Solutions acquisition and for other corporate purposes. We recorded a gain on sale of assets, net of approximately $157 million during the year ended December 31, 2016, and our federal and state NOLs almost entirely offset the taxable gain from the sale. South Point Energy Center As a result of the denial by the Nevada Public Utility Commission of the sale of South Point Energy Center to Nevada Power Company in February 2017, we terminated the corresponding asset sale agreement (originally executed on April 1, 2016) in the first quarter of 2017. During the first quarter of 2017, we reclassified the assets of South Point Energy Center from current assets held for sale to held and used at fair value. |
Property, Plant and Equipment,
Property, Plant and Equipment, Net | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment, Net [Abstract] | |
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net As of December 31, 2018 and 2017 , the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions): 2018 2017 Depreciable Lives Buildings, machinery and equipment $ 16,400 $ 16,506 1.5 – 46 Years Geothermal properties 1,501 1,494 13 – 58 Years Other 286 236 3 – 46 Years 18,187 18,236 Less: Accumulated depreciation 6,832 6,383 11,355 11,853 Land 121 117 Construction in progress 966 754 Property, plant and equipment, net $ 12,442 $ 12,724 Total depreciation expense, including amortization of capital lease assets, recorded for the years ended December 31, 2018 , 2017 and 2016 , was $684 million , $638 million and $628 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. Depreciable Lives — During the fourth quarter of 2017, we reviewed our accounting policies related to depreciation associated with our estimates of useful lives related to our componentized balance of plant parts. During the first quarter of 2018, we reviewed our accounting policies related to depreciation associated with our estimates of useful lives related to our rotable parts. As a result, the useful lives of our componentized balance of plant parts are now generally estimated to range from 6 to 25 years and the useful lives of our rotable parts are now generally estimated to range from 1.5 to 12 years. Our change in the estimated useful lives for componentized balance of plant parts and rotable parts is considered a change in accounting estimate and will result in changes to our depreciation expense prospectively. The change in estimate resulted in a (decrease) to our net income attributable to Calpine of $(24) million for the year ended December 31, 2018 . Buildings, Machinery and Equipment This component primarily includes power plants and related equipment. Included in buildings, machinery and equipment are assets under capital leases. See Note 8 for further information regarding these assets under capital leases. Geothermal Properties This component primarily includes power plants and related equipment associated with our Geysers Assets. Other This component primarily includes software and emission reduction credits that are power plant specific and not available to be sold. Capitalized Interest The total amount of interest capitalized was $29 million , $26 million and $21 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. |
Variable Interest Entities and
Variable Interest Entities and Unconsolidated Investments | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 . 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 3 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 has a ten-year tolling agreement with SDG&E which commenced on October 3, 2009. Under a ground lease agreement, OMEC holds 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 is 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, which will commence on October 3, 2019. The RA contract received initial regulatory approval by the California Public Utilities Commission (“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. While we have no way of predicting the outcome of the appeals process, we continue to evaluate alternatives. OMEC will exercise the put before April 1, 2019. In the event that either the appeal of the RA contract decision is not decided or another alternative is not agreed to by the parties prior to October 3, 2019, OMEC expects to close on the put and transfer the Otay Mesa Energy Center to SDG&E for $280 million on or about October 3, 2019, which transaction could result in a write down of the carrying value of the asset. On December 19, 2018, we refinanced the project debt associated with OMEC which lowered the aggregate debt balance to $220 million and extended the maturity to August 2024. In the event that the OMEC put option is exercised, the debt will become payable on November 3, 2019. We have concluded that we are the primary beneficiary of OMEC as we believe the activity that has the most effect on the financial performance of OMEC is operations and maintenance which is controlled by us. As a result, we consolidate OMEC. 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 — We own a 75% interest in Russell City Energy Company, LLC, one of our VIEs, which is also 25% owned by a third party. We fully consolidate this entity in our Consolidated Financial Statements and account 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 7,880 MW and 7,880 MW, at December 31, 2018 and 2017 , 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. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil , nil and $115 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. 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 (primarily 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 and where the amounts are material to our financial statements. Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. 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. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby. In December 2016, we acquired Calpine Receivables, a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. Calpine Receivables is a VIE as 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 as 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, 2018 and 2017 , our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions): Ownership Interest as of December 31, 2018 2018 2017 Greenfield LP 50% $ 55 $ 92 Whitby 50% 15 6 Calpine Receivables 100% 6 8 Total investments in unconsolidated subsidiaries $ 76 $ 106 Our risk of loss related to our investments in Greenfield LP and Whitby is limited to our investment balance. Our risk of loss related to our investment in Calpine Receivables is $44 million which consists of our notes receivable from Calpine Receivables at December 31, 2018 , 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. On October 5, 2018, Greenfield LP refinanced and upsized its debt. At December 31, 2018 and 2017 , Greenfield LP’s debt was approximately $301 million and $ 256 million , respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $151 million and $ 128 million at December 31, 2018 and 2017 , respectively. Our equity interest in the net income from our investments in unconsolidated subsidiaries for the years ended December 31, 2018 , 2017 and 2016 , 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 2018 2017 2016 2018 2017 2016 Greenfield LP $ (11 ) $ (14 ) $ (10 ) $ 48 $ 8 $ 8 Whitby (15 ) (10 ) (14 ) 5 20 13 Calpine Receivables 2 2 — — — — Total $ (24 ) $ (22 ) $ (24 ) $ 53 $ 28 $ 21 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 are 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 site infrastructure and equipment at a future date. We have determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to the fact that GE continues to direct the most significant activities of the power plant including operations and maintenance, and will continue in this capacity until the point that the facility site is transferred to Calpine. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt | Debt Our debt at December 31, 2018 and 2017 , was as follows (in millions): 2018 2017 Senior Unsecured Notes $ 3,036 $ 3,417 First Lien Term Loans 2,976 2,995 First Lien Notes 2,400 2,396 Project financing, notes payable and other 1,264 1,498 CCFC Term Loan 974 984 Capital lease obligations 105 115 Corporate Revolving Facility 30 — Subtotal 10,785 11,405 Less: Current maturities 637 225 Total long-term debt $ 10,148 $ 11,180 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, 2018 . Annual Debt Maturities Contractual annual principal repayments or maturities of debt instruments as of December 31, 2018 , are as follows (in millions): 2019 $ 642 2020 246 2021 259 2022 1,019 2023 2,535 Thereafter 6,217 Subtotal 10,918 Less: Debt issuance costs 112 Less: Discount 21 Total debt $ 10,785 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) 2018 2017 2018 2017 2023 Senior Unsecured Notes $ 1,227 $ 1,239 5.6 % 5.6 % 2024 Senior Unsecured Notes 599 644 5.7 5.7 2025 Senior Unsecured Notes 1,210 1,534 6.0 6.0 Total Senior Unsecured Notes $ 3,036 $ 3,417 ____________ (1) Our weighted average interest rate calculation includes the amortization 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. Principal Repurchased Cash Paid Gain on Extinguishment of Debt (in million) 2023 Senior Unsecured Notes $ 14 $ 13 $ 1 2024 Senior Unsecured Notes 46 42 4 2025 Senior Unsecured Notes 330 300 30 Total $ 390 $ 355 $ 35 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) 2018 2017 2018 2017 2019 First Lien Term Loan $ 389 $ 389 4.9 % 4.1 % 2023 First Lien Term Loans 1,059 1,064 5.4 4.6 2024 First Lien Term Loan (2) 1,528 1,542 5.0 4.2 Total First Lien Term Loans $ 2,976 $ 2,995 ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. (2) Our 2024 First Lien Term Loan carries substantially similar terms as our 2023 First Lien Term Loans as discussed below. On February 3, 2017, we entered into a $400 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 2019 First Lien Term Loan credit agreement), plus an applicable margin of 0.75% , or (ii) LIBOR plus 1.75% per annum (with no LIBOR floor) and matures on December 31, 2019. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2019 First Lien Term Loans is payable at the end of each quarter (beginning with the quarter ending June 2017) 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 of the 2019 First Lien Term Loan, which is structured as original issue discount and recorded approximately $8 million in debt issuance costs during the first quarter of 2017 related to the issuance of our 2019 First Lien Term Loan. The 2019 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as other First Lien Term Loans and the First Lien Notes. We used the proceeds from the 2019 First Lien Term Loan, together with cash on hand, to redeem the remaining 2023 First Lien Notes. On May 31, 2016, we entered into a $562 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 2.00% , or (ii) LIBOR plus 2.75% per annum (with no LIBOR floor) and matures on May 31, 2023. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2023 First Lien Term Loans 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 of the 2023 First Lien Term Loans, which is structured as original issue discount and recorded approximately $11 million in debt issuance costs during the second quarter of 2016 related to the issuance of this portion of our 2023 First Lien Term Loans. The 2023 First Lien Term Loans contains substantially similar covenants, qualifications, exceptions and limitations as other First Lien Term Loans and the First Lien Notes. We used the proceeds from this portion of our 2023 First Lien Term Loans and a portion of our 2026 First Lien Notes, discussed below, to repay portion of our First Lien Term Loans with maturity dates in 2019 and 2020 and recorded $15 million in loss on extinguishment of debt during the second quarter of 2016 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) 2018 2017 2018 2017 2022 First Lien Notes $ 743 $ 741 6.4 % 6.4 % 2024 First Lien Notes 486 485 6.1 6.1 2026 First Lien Notes 1,171 1,170 5.5 5.5 Total First Lien Notes $ 2,400 $ 2,396 ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. 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) 2018 2017 2018 2017 Russell City due 2023 $ 341 $ 401 6.5 % 6.4 % Steamboat due 2025 384 414 4.5 4.7 OMEC due 2024 (2) 218 294 7.1 7.2 Los Esteros due 2023 163 191 4.7 5.3 Pasadena (3) 76 89 8.9 8.9 Bethpage Energy Center 3 due 2020-2025 (4) 53 60 7.1 7.1 Other 29 49 — — Total $ 1,264 $ 1,498 _____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. (2) On December 19, 2018, we refinanced the project debt associated with OMEC which lowered the aggregate debt balance to $220 million and extended the maturity to August 2024. In the event that the OMEC put option is exercised, the debt will become payable on November 3, 2019. See Note 7 for further information related to the OMEC put option. (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. 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. If PG&E does not seek to assume our PPAs through their bankruptcy proceedings, unless otherwise modified, we will incur an event of default under the Russell City and Los Esteros project debt agreements 180 days after the date of PG&E’s bankruptcy filing. 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) 2018 2017 2018 2017 CCFC Term Loan $ 974 $ 984 4.9 % 4.6 % ____________ (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% per annum, plus an applicable margin of 1.5% per annum, or (ii) LIBOR plus 2.5% per annum. 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. Capital Lease Obligations The following is a schedule by year of future minimum lease payments under capital leases and a failed sale-leaseback transaction related to our Pasadena Power Plant together with the present value of the net minimum lease payments as of December 31, 2018 (in millions): Sale-Leaseback Transaction (1) Capital Lease Total 2019 $ 21 $ 19 $ 40 2020 21 19 40 2021 21 17 38 2022 16 17 33 2023 6 21 27 Thereafter 20 72 92 Total minimum lease payments 105 165 270 Less: Amount representing interest 29 60 89 Present value of net minimum lease payments $ 76 $ 105 $ 181 ____________ (1) Amounts are accounted for as a financing transaction under U.S. GAAP and are included in our project financing, notes payable and other amounts above. The primary types of property leased by us are power plants and related equipment. The leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. The remaining lease terms range up to 33 years (including lease renewal options). Some of the lease agreements contain customary restrictions on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project financing agreements. At December 31, 2018 and 2017 , the asset balances for the leased assets totaled approximately $715 million and $737 million with accumulated amortization of $353 million and $349 million , respectively. Amortization of assets under capital leases is recorded in depreciation and amortization expense on our Consolidated Statements of Operations. See Note 16 for discussion of capital leases guaranteed by Calpine Corporation. Corporate Revolving Facility and Other Letters of Credit Facilities The table below represents amounts issued under our letter of credit facilities at December 31, 2018 and 2017 (in millions): 2018 2017 Corporate Revolving Facility $ 693 $ 629 CDHI 251 244 Various project financing facilities 228 196 Other corporate facilities 193 — Total $ 1,365 $ 1,069 Corporate Revolving Facility On May 18, 2018, we amended our Corporate Revolving Facility to increase the capacity by approximately $220 million from $1.47 billion to approximately $1.69 billion . On March 8, 2018, we amended our Corporate Revolving Facility to increase the letter of credit facility from $1.15 billion to $1.3 billion and increased the Incremental Revolving Facilities (as defined in the credit agreement) amount to $500 million . On September 15, 2017, we amended our Corporate Revolving Facility to, among other things, provide that the Merger does not constitute a “Change of Control” thereunder, effective upon consummation of the Merger. On October 20, 2017, we further amended our Corporate Revolving Facility to extend the maturity of most revolving commitments (totaling $1.3 billion in the aggregate) to March 8, 2023. Both amendments to the Corporate Revolving Facility became effective upon consummation of the Merger on March 8, 2018. See Note 2 for further information related to the Merger. 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 letter of credit facility related to CDHI. During the fourth quarter of 2017, we amended our CDHI letter of credit facility to extend the maturity to October 2, 2021. Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI letter of credit facility will be reduced to $125 million on June 30, 2019. The decrease in capacity will not have a material effect on our liquidity as alternative sources of liquidity are available. Other corporate facilities We have two unsecured letter of credit facilities with third party financial institutions totaling $200 million . One of the facilities, with commitments totaling $150 million , matures partially in June 2020 and fully by December 2020. The other facility, with commitments totaling $50 million , matures in June 2020. Short Term Credit Facility On April 11, 2018, we entered into a credit agreement which allowed us access to $300 million in aggregate available borrowings until August 31, 2018. We did not make any cash draws on the Short Term Credit Facility which we terminated on August 17, 2018. 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, 2018 and 2017 (in millions): 2018 2017 Fair Value Carrying Fair Value Carrying Value Senior Unsecured Notes $ 2,803 $ 3,036 $ 3,294 $ 3,417 First Lien Term Loans 2,877 2,976 3,043 2,995 First Lien Notes 2,299 2,400 2,437 2,396 Project financing, notes payable and other (1) 1,209 1,188 1,439 1,409 CCFC Term Loan 938 974 1,000 984 Corporate Revolving Facility 30 30 — — Total $ 10,156 $ 10,604 $ 11,213 $ 11,201 ____________ (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, CCFC Term Loan and Corporate Revolving Facility are categorized as level 2 within the fair value hierarchy. Our 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, 2018 | |
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, 2018 and 2017 , by level within the fair value hierarchy: 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 Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2017 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 131 $ — $ — $ 131 Commodity instruments: Commodity exchange traded derivatives contracts 746 — — 746 Commodity forward contracts (2) — 327 265 592 Interest rate hedging instruments — 29 — 29 Effect of netting and allocation of collateral (3)(4) (746 ) (206 ) (23 ) (975 ) Total assets $ 131 $ 150 $ 242 $ 523 Liabilities: Commodity instruments: Commodity exchange traded derivatives contracts 790 — — 790 Commodity forward contracts (2) — 461 68 529 Interest rate hedging instruments — 34 — 34 Effect of netting and allocation of collateral (3)(4) (790 ) (224 ) (23 ) (1,037 ) Total liabilities $ — $ 271 $ 45 $ 316 ___________ (1) As of December 31, 2018 and 2017 , we had cash equivalents of $23 million and $21 million included in cash and cash equivalents and $145 million and $110 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 $(1) million , $48 million and nil , respectively, at December 31, 2018 . Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $44 million , $18 million and nil , respectively, at December 31, 2017 . At December 31, 2018 and 2017 , 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, 2018 and 2017 : 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 Quantitative Information about Level 3 Fair Value Measurements December 31, 2017 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts (1) $ 149 Discounted cash flow Market price (per MWh) $4.13 — $119.20/MWh Power Congestion Products $ 11 Discounted cash flow Market price (per MWh) $(10.54) — $9.13/MWh Natural Gas Contracts $ 34 Discounted cash flow Market price (per MMBtu) $1.62 — $13.67/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, 2018 , 2017 and 2016 (in millions): 2018 2017 2016 Balance, beginning of period $ 197 $ 416 $ (46 ) Realized and mark-to-market gains (losses): Included in net income (loss): Included in operating revenues (1) (88 ) 32 (46 ) Included in fuel and purchased energy expense (2) (45 ) 50 7 Change in collateral — (17 ) 17 Purchases, issuances and settlements: Purchases (3) 18 4 426 Issuances (2 ) (1 ) — Settlements (86 ) (179 ) (21 ) Transfers in and/or out of level 3 (4) : Transfers into level 3 (5) — (2 ) 4 Transfers out of level 3 (6) (2 ) (106 ) 75 Balance, end of period $ (8 ) $ 197 $ 416 Change in unrealized gains (losses) relating to instruments still held at end of period $ (133 ) $ 82 $ (39 ) ___________ (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) During December 2016, we had $421 million in purchases related to the acquisition of Calpine Solutions, formerly Noble Solutions. (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, 2018 , 2017 and 2016 . (5) We had nil and $(2) million in losses and $4 million in gains transferred out of level 2 into level 3 for the years ended December 31, 2018 , 2017 and 2016 , respectively. (6) We had $2 million and $104 million in gains and $(75) million in losses transferred out of level 3 into level 2 during the years ended December 31, 2018 , 2017 and 2016 , 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, 2018 | |
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, 2018 , 2017 and 2016. 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, 2018 , the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 7 years. As of December 31, 2018 and 2017 , 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 2018 2017 Power (MWh) (161 ) (119 ) Natural gas (MMBtu) 1,045 405 Environmental credits (Tonnes) 13 12 Interest rate hedging instruments $ 4,500 $ 4,600 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, 2018 , was $229 million for which we have posted collateral of $178 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 effective portion of 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. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. 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 are 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, 2018 and 2017 (in millions): 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 (2) $ 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 (2) $ 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) (2) $ (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) (2) $ (367 ) $ 227 $ (140 ) Total derivative liabilities $ (1,711 ) $ 1,268 $ (443 ) Net derivative assets (liabilities) $ (188 ) $ 47 $ (141 ) December 31, 2017 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 $ 672 $ (672 ) $ — Commodity forward contracts 361 (194 ) 167 Interest rate hedging instruments 7 — 7 Total current derivative assets (3) $ 1,040 $ (866 ) $ 174 Commodity exchange traded derivatives contracts 74 (74 ) — Commodity forward contracts 231 (32 ) 199 Interest rate hedging instruments 22 (3 ) 19 Total long-term derivative assets (3) $ 327 $ (109 ) $ 218 Total derivative assets $ 1,367 $ (975 ) $ 392 Derivative (liabilities): Commodity exchange traded derivatives contracts $ (702 ) $ 702 $ — Commodity forward contracts (389 ) 209 (180 ) Interest rate hedging instruments (17 ) — (17 ) Total current derivative (liabilities) (3) $ (1,108 ) $ 911 $ (197 ) Commodity exchange traded derivatives contracts (88 ) 88 — Commodity forward contracts (140 ) 35 (105 ) Interest rate hedging instruments (17 ) 3 (14 ) Total long-term derivative (liabilities) (3) $ (245 ) $ 126 $ (119 ) Total derivative liabilities $ (1,353 ) $ 1,037 $ (316 ) Net derivative assets (liabilities) $ 14 $ 62 $ 76 ____________ (1) At December 31, 2018 and 2017 , we had $244 million and $155 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, 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. (3) At December 31, 2017 , current and long-term derivative assets are shown net of collateral of $(8) million and $(2) million , respectively, and current and long-term derivative liabilities are shown net of collateral of $52 million and $20 million , respectively. December 31, 2018 December 31, 2017 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 $ 40 $ 10 $ 26 $ 31 Total derivatives designated as cash flow hedging instruments $ 40 $ 10 $ 26 $ 31 Derivatives not designated as hedging instruments: Commodity instruments $ 262 $ 433 $ 366 $ 285 Total derivatives not designated as hedging instruments $ 262 $ 433 $ 366 $ 285 Total derivatives $ 302 $ 443 $ 392 $ 316 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 the effective portion of 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, 2018 , 2017 and 2016 (in millions): 2018 2017 2016 Realized gain (loss) (1)(2) Commodity derivative instruments $ 193 $ 7 $ 235 Total realized gain $ 193 $ 7 $ 235 Mark-to-market gain (loss) (3) Commodity derivative instruments $ (208 ) $ (171 ) $ (1 ) Interest rate hedging instruments 3 2 2 Total mark-to-market gain (loss) $ (205 ) $ (169 ) $ 1 Total activity, net $ (12 ) $ (162 ) $ 236 ___________ (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, Calpine Solutions and North American Power. (3) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. 2018 2017 2016 Realized and mark-to-market gain (loss) (1) Derivatives contracts included in operating revenues (2)(3) $ (369 ) $ (69 ) $ 109 Derivatives contracts included in fuel and purchased energy expense (2)(3) 354 (95 ) 125 Interest rate hedging instruments included in interest expense 3 2 2 Total activity, net $ (12 ) $ (162 ) $ 236 ___________ (1) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and 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, Calpine Solutions and North American Power. 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, 2018 , 2017 and 2016 (in millions): Gain (Loss) Recognized in OCI (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) (3)(4) 2018 2017 2016 2018 2017 2016 Affected Line Item on the Consolidated Statements of Operations Interest rate hedging instruments (1)(2) $ 45 $ 21 $ 41 $ (5 ) $ (43 ) $ (43 ) Interest expense Interest rate hedging instruments (1)(2) 1 5 — (1 ) (5 ) — Depreciation expense Total $ 46 $ 26 $ 41 $ (6 ) $ (48 ) $ (43 ) ____________ (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 . We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the year ended December 31, 2016 . (2) We recorded income tax expense of $5 million , $6 million and $1 million for the years ended December 31, 2018 , 2017 and 2016 , 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 $34 million , $72 million and $90 million at December 31, 2018 , 2017 and 2016 , respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million , $ 6 million and $ 8 million at December 31, 2018 , 2017 and 2016 , respectively. (4) Includes losses of $1 million , nil and $3 million that were reclassified from AOCI to interest expense for the years ended December 31, 2018 , 2017 and 2016 , respectively, where the hedged transactions became probable of not occurring. We estimate that pre-tax net gains of $11 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, 2018 | |
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, 2018 and 2017 (in millions): 2018 2017 Margin deposits (1) $ 343 $ 221 Natural gas and power prepayments 31 23 Total margin deposits and natural gas and power prepayments with our counterparties (2) $ 374 $ 244 Letters of credit issued $ 1,166 $ 885 First priority liens under power and natural gas agreements 92 102 First priority liens under interest rate hedging instruments 10 31 Total letters of credit and first priority liens with our counterparties $ 1,268 $ 1,018 Margin deposits posted with us by our counterparties (1)(3) $ 52 $ 4 Letters of credit posted with us by our counterparties 27 30 Total margin deposits and letters of credit posted with us by our counterparties $ 79 $ 34 ___________ (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, 2018 and 2017 , $79 million and $64 million , respectively, were included in current and long-term derivative assets and liabilities, $286 million and $171 million , respectively, were included in margin deposits and other prepaid expense and $9 million and $9 million , respectively, were included in other assets on our Consolidated Balance Sheets. (3) At December 31, 2018 and 2017 , $32 million and $2 million , respectively, were included in current and long-term derivative assets and liabilities and $20 million and $2 million , respectively, were included in other current 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, 2018 | |
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 will affect 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, 2018 , 2017 and 2016 , are as follows (in millions): 2018 2017 2016 U.S. $ 47 $ (358 ) $ 116 International 27 27 24 Total $ 74 $ (331 ) $ 140 The components of income tax expense from continuing operations for the years ended December 31, 2018 , 2017 and 2016 , consisted of the following (in millions): 2018 2017 2016 Current: Federal $ — $ (10 ) $ (10 ) State 20 18 14 Foreign (3 ) (14 ) 1 Total current 17 (6 ) 5 Deferred: Federal (1 ) 5 10 State (6 ) 6 27 Foreign 54 3 6 Total deferred 47 14 43 Total income tax expense $ 64 $ 8 $ 48 For the years ended December 31, 2018 , 2017 and 2016 , 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, 2018 , 2017 and 2016 , is as follows: 2018 2017 2016 Federal statutory tax rate 21.0 % 35.0 % 35.0 % State tax expense, net of federal benefit 17.0 (6.0 ) 19.4 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 (31.7 ) (33.0 ) (25.0 ) Valuation allowance related to foreign taxes (138.3 ) 0.5 (0.1 ) Decrease in foreign NOL due to change in ownership 202.3 — — Distributions from foreign affiliates and foreign taxes 6.6 (2.0 ) (0.6 ) Change in unrecognized tax benefits (8.0 ) 5.1 (0.1 ) Disallowed compensation 7.7 (0.6 ) 0.9 Stock-based compensation (1.5 ) (0.9 ) 2.2 Equity earnings 1.4 (0.8 ) 2.0 Merger Related Fees/Expenses 12.7 — — Depletion in excess of basis (4.0 ) — — Other differences 1.3 0.3 0.6 Effective income tax rate 86.5 % (2.4 )% 34.3 % Deferred Tax Assets and Liabilities The components of deferred income taxes as of December 31, 2018 and 2017 , are as follows (in millions): 2018 2017 Deferred tax assets: NOL and credit carryforwards $ 1,595 $ 1,810 Taxes related to risk management activities and derivatives 7 20 Reorganization items and impairments 166 146 Other differences 101 28 Deferred tax assets before valuation allowance 1,869 2,004 Valuation allowance (1,000 ) (1,168 ) Total deferred tax assets 869 836 Deferred tax liabilities: Property, plant and equipment (890 ) (805 ) Total deferred tax liabilities (890 ) (805 ) Net deferred tax asset (liability) (21 ) 31 Less: Non-current deferred tax liability (22 ) (28 ) Deferred income tax asset, non-current $ 1 $ 59 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 $1 million , $6 million and nil for the years ended December 31, 2018 , 2017 and 2016 . NOL Carryforwards — As of December 31, 2018 , our NOL carryforwards consisted primarily of federal NOL carryforwards of approximately $6.4 billion , which expire between 2024 and 2037 , and NOL carryforwards in 26 states and the District of Columbia totaling approximately $3.3 billion , which expire between 2019 and 2038 . Substantially all of the federal and state NOLs are offset with a full 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 will be limited. 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 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 have concluded our U.S. federal income tax examination for the year ended December 31, 2015 with no adjustments. We are currently under various state income tax audits for various periods. Our Canadian subsidiaries are currently under examination by the Canada Revenue Agency for the years ended December 31, 2013 through 2016. 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, 2018 , we have provided a valuation allowance of approximately $ 1.0 billion 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 $ 168 million for the year ended December 31, 2018 , primarily related to the loss of utilization of our foreign NOLs as a result of the Merger and to income generated in 2018. We had a reduction in our valuation allowance of $ 413 million and $ 56 million for the years ended December 31, 2017 and 2016 , respectively, primarily related to income generated in these periods. Deductions on Business Interest Expense — On November 26, 2018, the U.S. Treasury Department released proposed regulations which limit business interest expense deductions. 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 retroactively to taxable years beginning after December 31, 2017, but must apply all such rules on a consistent basis. We have not elected to apply the proposed regulations for the year ended December 31, 2018 and do not expect the application of the final regulations to have a material effect on our Consolidated Financial Statements. Unrecognized Tax Benefits At December 31, 2018 , we had unrecognized tax benefits of $28 million . If recognized, $16 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 $2 million and $4 million for income tax matters at December 31, 2018 and 2017 , respectively. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Statements of Operations and recorded $(2) million , $(8) million and nil for the years ended December 31, 2018 , 2017 and 2016 , respectively. We believe that it is reasonably possible that a decrease within the range of nil and $1 million in unrecognized tax benefits could occur within the next twelve months primarily related to federal tax issues. A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2018 , 2017 and 2016 , is as follows (in millions): 2018 2017 2016 Balance, beginning of period $ (38 ) $ (59 ) $ (58 ) Increases related to prior year tax positions (7 ) — — Decreases related to prior year tax positions 17 11 1 Increases related to current year tax positions — (2 ) (2 ) Decreases related to change in tax rate of net deferred tax asset — 12 — Balance, end of period $ (28 ) $ (38 ) $ (59 ) |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [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. 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 , $36 million and $30 million for the years ended December 31, 2018 , 2017 and 2016 , 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 , $ 6 million and $1 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. The total intrinsic value of our employee stock options exercised was $11 million , nil and $ 1 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. The total cash proceeds received from our employee stock options exercised was nil , nil and $1 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. The total fair value of our restricted stock and restricted stock units that vested during the years ended December 31, 2018 , 2017 and 2016 was approximately $88 million , $23 million and $17 million , respectively. |
Defined Contribution and Define
Defined Contribution and Defined Benefit Plans | 12 Months Ended |
Dec. 31, 2018 | |
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 , $14 million and $11 million for the years ended December 31, 2018 , 2017 and 2016 , 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 a defined benefit pension plan whereby retirement benefits are primarily a function of age attained, years of participation, years of service, vesting and level of compensation. Only approximately 3% of our employees are eligible to participate in a defined benefit pension plan. As of December 31, 2018 and 2017 , there were approximately $19 million and $21 million in plan assets and approximately $27 million and $29 million in pension liabilities, respectively. Our net pension liability recorded on our Consolidated Balance Sheets as of December 31, 2018 and 2017 , was approximately $8 million and $8 million , respectively. For the years ended December 31, 2018 , 2017 and 2016 , we recognized net periodic benefit costs of approximately $1 million , $1 million and $2 million , respectively. Our net periodic benefit cost is included in operating and maintenance expense on our Consolidated Statements of Operations. As of December 31, 2018 and 2017 , the total amount recognized in AOCI for actuarial losses related to pension obligation was approximately $4 million and $5 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 2018 and 2017 , we made contributions of approximately $1 million and $2 million , respectively, and estimated contributions to the pension plan are expected to be approximately $4 million in 2018. 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, 2018 | |
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. See Notes 2 and 13 for a discussion of the Merger and treatment of the outstanding share-based awards to employees at the effective time of the Merger, respectively. Common Stock Our authorized common stock consists of 5,000 shares and 1.4 billion shares of Calpine Corporation common stock as of December 31, 2018 and 2017 , respectively. Common stock issued as of December 31, 2018 and 2017 , was 105.2 shares and 361,677,891 shares, respectively, at a par value of $0.001 per share. Common stock outstanding as of December 31, 2018 and 2017 , was 105.2 shares and 360,516,091 shares, respectively. The table below summarizes our common stock activity for the years ended December 31, 2018 , 2017 and 2016 . Shares Issued Shares Held in Treasury Shares Outstanding Balance, December 31, 2015 356,755,747 (93,743 ) 356,662,004 Shares issued under Calpine Equity Incentive Plans 2,871,366 (449,079 ) 2,422,287 Share repurchase program — (22,527 ) (22,527 ) 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 Treasury Stock As of December 31, 2018 and 2017 , we had treasury stock of nil shares and 1,161,800 shares, respectively, with a cost of nil and $15 million , respectively. Our treasury stock consists of shares repurchased as well as our common stock withheld to satisfy federal, state and local income tax withholding requirements for vested employee restricted stock awards and net share employee stock options exercises under the Equity Plan. All treasury stock was held at cost and retired at the effective time of the Merger in accordance with the Merger Agreement. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Long-Term Service Agreements As of December 31, 2018 , the total estimated commitments for LTSAs associated with turbines were approximately $243 million . These commitments are payable over the remaining terms of the respective agreements, which range from 1 to 19 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. The minimum contractually obligated amount at December 31, 2018 associated with our LTSAs is $18 million . Power Plant, Land and Other Operating Leases We have entered into a long-term operating lease for one of our power plants, extending through February 1, 2020 , which contains customary restrictions on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project finance agreements. Payments on our operating lease, which may contain escalation clauses or step rent provisions, are recognized on a straight-line basis. Certain capital improvements associated with our leased power plant may be deemed to be leasehold improvements and are amortized over the shorter of the term of the lease or the economic life of the capital improvement. We have also entered into various land and other operating leases for ground facilities and operations, which extend through 2068 . Future minimum rent payments under these lease agreements, including renewal options and rent escalation clauses, are as follows (in millions): Initial Year 2019 2020 2021 2022 2023 Thereafter Total Land and other operating leases various $ 13 $ 13 $ 12 $ 10 $ 10 $ 174 $ 232 Power plant operating lease 2000 31 — — — — — 31 Total leases $ 44 $ 13 $ 12 $ 10 $ 10 $ 174 $ 263 During the years ended December 31, 2018 , 2017 and 2016 , rent expense for power plant, land and other operating leases amounted to $43 million , $41 million and $38 million , respectively. Production Royalties and Leases We are obligated under numerous geothermal leases and right-of-way, easement and surface agreements. The geothermal leases 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 leases, 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 lease royalties. Some lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level. Production royalties for geothermal power plants for the years ended December 31, 2018 , 2017 and 2016 , were $26 million , $25 million and $22 million , respectively. Office Leases We lease our corporate and regional offices under noncancellable operating leases extending through 2025 . Future minimum lease payments under these leases are as follows (in millions): 2019 $ 6 2020 6 2021 8 2022 8 2023 7 Thereafter 18 Total $ 53 Lease payments are subject to adjustments for our pro rata portion of annual increases or decreases in building operating costs. During the years ended December 31, 2018 , 2017 and 2016 , rent expense for noncancelable operating leases was $10 million , $9 million and $9 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, 2018 , we had future commitments for the purchase, transportation, or storage of commodities as detailed below (in millions): 2019 $ 415 2020 172 2021 134 2022 101 2023 93 Thereafter 201 Total $ 1,116 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, 2018 , 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 2019 2020 2021 2022 2023 Thereafter Total Guarantee of subsidiary debt (1) $ 30 $ 30 $ 29 $ 24 $ 14 $ 52 $ 179 Standby letters of credit (2)(3)(4) 1,321 6 — — 38 — 1,365 Surety bonds (4)(5)(6) 12 7 — — — 76 95 Guarantee under Accounts Receivable Sales Program (7) 238 — — — — — 238 Total $ 1,601 $ 43 $ 29 $ 24 $ 52 $ 128 $ 1,877 ____________ (1) Represents Calpine Corporation guarantees of certain power plant capital leases and related interest. All guaranteed capital 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, 2018 , 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 29, 2019 . 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, 2018 , 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. Former Stockholder Appraisal Rights — After the Merger, we received demands for appraisal pursuant to Section 262 of the Delaware General Corporate Law from certain dissenting stockholders. In May and July 2018, we entered into settlement agreements which resolved the appraisal claims with the stockholders that demanded a statutory right to appraisal of their shares. In July 2018, one such dissenting stockholder filed a petition for appraisal in the Delaware Chancery Court, captioned Marble Holdings LLC v. Calpine Corporation , C.A. No. 2018-0492. The case was subsequently dismissed pursuant to settlement. As a result of the settlement agreements, we recorded a charge of approximately $52 million to other (income) expense, net on our Consolidated Statement of Operation during the year ended December 31, 2018 . 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, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions Disclosure [Text Block] | 17. 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 (see Note 2 for a description of the Merger): 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 29, 2019 . Calpine Solutions services the receivables sold in exchange for a servicing fee which was not material for the years ended December 31, 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, 2018 and 2017 , we had $238 million and $196 million , respectively, in trade accounts receivable outstanding that were sold under the Accounts Receivable Sales Program and $34 million and $26 million , respectively, in notes receivable which was recorded on our Consolidated Balance Sheets. We sold an aggregate of approximately $2.4 billion , $2.2 billion and $165 million in trade accounts receivable and recorded proceeds of approximately $2.3 billion , $2.2 billion and $165 million during the years ended December 31, 2018 , 2017 and 2016 , 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, 2018 , 2017 and 2016 . 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 which closed on March 8, 2018, 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, 2018 , we recorded $76 million and $12 million in Commodity revenue and Commodity expense, respectively, associated with Lyondell. At December 31, 2018 the related party receivables and payables associated with Lyondell were immaterial. Other — Following the Merger, we have identified other related party contracts for the sale of power, capacity 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. The terms of most of these contracts were negotiated prior to the Merger. At December 31, 2018 , the related party receivables and payables associated with these transactions were immaterial. |
Segment and Significant Custome
Segment and Significant Customer Information | 12 Months Ended |
Dec. 31, 2018 | |
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. During the first quarter of 2018, we altered the composition of our segments to report the results associated with our retail business as a separate segment. This change reflects the manner in which our segment information is presented internally to our chief operating decision maker associated with the strategic utilization of our retail business subsequent to the consummation of the Merger. Thus, beginning in the first quarter of 2018, 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. The tables below have been updated to present our segments on this revised basis for all periods. 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, 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 ) Year Ended December 31, 2016 Wholesale West Texas East Retail Consolidation and Elimination Total Total operating revenues (1) $ 1,545 $ 2,145 $ 1,657 $ 1,520 $ (151 ) $ 6,716 Commodity Margin $ 984 $ 543 $ 905 $ 172 $ — $ 2,604 Add: Mark-to-market commodity activity, net and other (2) (11 ) 12 15 (62 ) (29 ) (75 ) Less: Operating and maintenance expense 355 298 312 41 (29 ) 977 Depreciation and amortization expense 224 205 214 19 — 662 General and other administrative expense 38 56 40 6 — 140 Other operating expenses 33 8 38 — — 79 Impairment losses 13 — — — — 13 (Gain) on sale of assets, net — — (157 ) — — (157 ) (Income) from unconsolidated subsidiaries — — (24 ) — — (24 ) Income (loss) from operations 310 (12 ) 497 44 — 839 Interest expense 631 Debt modification and extinguishment costs and other (income) expense, net 49 Income before income taxes $ 159 __________ (1) Includes intersegment revenues of $488 million , $324 million and $20 million in the West, $573 million , $361 million and $81 million in Texas, $234 million , $237 million and $48 million in the East and $4 million , $4 million , $2 million in Retail for the years ended December 31, 2018 , 2017 and 2016 , respectively. (2) Includes nil , $(8) million and $(2) million of lease levelization and $104 million , $178 million and $122 million of amortization expense for the years ended December 31, 2018 , 2017 and 2016 , respectively. Significant Customers For the year ended December 31, 2018 , 2017 and 2016 , 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, 2018 | |
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) 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 ) 2017 Operating revenues $ 1,801 $ 2,586 $ 2,084 $ 2,281 Income (loss) from operations $ (100 ) $ 393 $ 13 $ 72 Net income (loss) attributable to Calpine $ (292 ) $ 225 $ (216 ) $ (56 ) |
Schedule of Valuation and Quali
Schedule of Valuation and Qualifying Accounts Disclosure | 12 Months Ended |
Dec. 31, 2018 | |
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, 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 Year Ended December 31, 2016 Allowance for doubtful accounts $ 2 $ 4 $ — $ — $ 6 Deferred tax asset valuation allowance 1,637 (56 ) — — 1,581 ____________ (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, 2018 | |
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, Whitby, 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, CCFC Term Loan and Corporate Revolving Facility are categorized as level 2 within the fair value hierarchy. Our 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 $14 million , $27 million and $24 million of business interruption proceeds in operating revenues for the years ended December 31, 2018 , 2017 , and 2016 , 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 mininimis 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 during the third quarter and whenever the events or changes in circumstances indicate that the carrying value may not be recoverable. During the first quarter of 2018, we altered the composition of our segments to report the results associated with our retail business as a separate segment. This change reflects the manner in which our segment information is presented internally to our chief operating decision maker associated with the strategic utilization of our retail business subsequent to the consummation of the Merger. Thus, beginning in the first quarter of 2018, 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. As our goodwill resulted from the acquisition of our retail business over the last several years, our goodwill balance of $242 million was allocated to our Retail segment in connection with the change in segment presentation. We did not record any changes in the carrying amount of our goodwill during the year ended December 31, 2018 . During the year ended December 31, 2017 , we recorded goodwill of $49 million associated with our acquisition of North American Power and recorded $6 million in purchase price adjustments. 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 contractual 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, 2018 , 2017 and 2016 . 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, 2018 and 2017 , our asset retirement obligation liabilities were $63 million and $43 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 fixed and variable capacity payments, which are not related to generation including capacity payments received from RTO and ISO capacity auctions, variable payments for power and steam, which are related to generation, retail power revenues, host steam and RECs 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 4 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 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 year ended December 31, 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 year ended December 31, 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. |
Lease, Policy | 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. We apply lease accounting to contracts that meet the definition of a lease and accrual accounting treatment to those contracts that are either exempt from derivative accounting or do not meet the definition of a derivative instrument. |
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 effective portion of 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. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. 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 are 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 purchase and sales commodity 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. |
Stock-Based Compensation | For our restricted stock and restricted stock units, we used our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. We used the Black-Scholes option pricing model to estimate the fair value of our employee stock options on the grant date. Our performance share units were measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. We included estimated forfeitures in the calculation of stock-based compensation expense. |
Treasury Stock | Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock. Upon retirement of treasury stock, the amounts in excess of par value are charged entirely to additional paid-in capital. |
New Accounting Pronouncements | Revenue Recognition — On January 1, 2018, we adopted Accounting Standards Update 2014-09, “Revenue from Contracts with Customers” (“Topic 606”) . The comprehensive new revenue recognition standard supersedes all pre-existing revenue recognition guidance. The core principle of Topic 606 is that a company will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding the recognition of revenue from contracts with customers. We adopted the new revenue recognition standards under Topic 606 using the modified retrospective method and applied Topic 606 to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning after December 31, 2017 are presented under Topic 606, while prior period amounts continue to be reported in accordance with historical accounting standards. The adoption of Topic 606 resulted in no adjustment to our opening retained earnings as of January 1, 2018. There was no material effect to our revenues, results of operations or cash flows for the year ended December 31, 2018 from the adoption of Topic 606 and we do not expect the new revenue standard to have a material effect on our results of operations in future periods. See Note 4 for additional disclosures required by Topic 606. Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified retrospective adoption with early adoption permitted. In January 2018, the FASB issued Accounting Standards Update 2018-01, “Land Easement Practical Expedient for Transition to Topic 842” that allows an entity to not evaluate existing and expired land easements that were not previously accounted for as leases upon adoption of Accounting Standards Update 2016-02. Any land easements entered into prospectively or modified after adoption should be evaluated to assess whether they meet the definition of a lease. In July 2018, the FASB issued Accounting Standards Update 2018-10 “Codification Improvements to Topic 842, Leases” which clarifies, corrects or consolidates authoritative guidance issued in Accounting Standards Update 2016-02 and is effective upon adoption of Accounting Standards Update 2016-02. Also in July 2018, the FASB issued Accounting Standards Update 2018-11 “Leases (Topic 842): Targeted Improvements” which provides a new transitional method to adopt the new leases standard and a practical expedient for lessors in applying the provisions of the new leases standard, which is effective upon adoption of Accounting Standards Update 2016-02. We will adopt the standards in the first quarter of 2019 and elect a number of the practical expedients in our implementation of the standards. The key change that will affect 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 will result in the recognition of a lease obligation liability of between $180 million and $200 million in our Consolidated Balance Sheet which will be largely offset by a right of use lease asset recognized on January 1, 2019. The implementation of the standards will not have a material effect on our Consolidated Statement of Operations. We are finalizing the evaluation of the effect of the additional recognition and disclosure requirements under the standards on our current processes and controls. Statement of Cash Flows — In August 2016, the FASB issued Accounting Standards Update 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” The standard addresses several matters of diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows including the presentation of debt extinguishment costs and distributions received from equity method investments. The standard is effective for fiscal years beginning after December 15, 2017, and requires retrospective adoption. We adopted Accounting Standards Update 2016-15 in the first quarter of 2018 which resulted in the reclassification of cash payments for debt extinguishment costs from a cash outflow for operating activities to a cash outflow for financing activities. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows. Income Taxes — In October 2016, the FASB issued Accounting Standards Update 2016-16, “Intra-Entity Transfers of Assets Other than Inventory.” The standard requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs which differs from the current requirement that prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period and requires modified retrospective adoption. We adopted Accounting Standards Update 2016-16 in the first quarter of 2018 which did not have a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. Restricted Cash — In November 2016, the FASB issued Accounting Standards Update 2016-18, “Restricted Cash.” The standard requires restricted cash to be included with cash and cash equivalents when reconciling the beginning and ending amounts in the statement of cash flows and also requires disclosures regarding the nature of restrictions on cash, cash equivalents and restricted cash. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and requires retrospective adoption with early adoption permitted. We adopted Accounting Standards Update 2016-18 in the first quarter of 2018 which did not have a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. 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. The standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. 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. |
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, 2018 | |
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, 2018 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress (in millions, except percentages) Freestone Energy Center 75.0 % $ 379 $ (167 ) $ 1 Hidalgo Energy Center 78.5 % $ 251 $ (114 ) $ 4 |
Schedule of Components of Restricted Cash | The table below represents the components of our restricted cash as of December 31, 2018 and 2017 (in millions): 2018 2017 Current Non-Current Total Current Non-Current Total Debt service $ 13 $ 8 $ 21 $ 11 $ 8 $ 19 Construction/major maintenance 23 24 47 28 16 44 Security/project/insurance 120 — 120 92 — 92 Other 11 2 13 3 1 4 Total $ 167 $ 34 $ 201 $ 134 $ 25 $ 159 |
Schedule of Intangible Assets and Goodwill [Table Text Block] | As of December 31, 2018 and 2017 , the components of our intangible assets were as follows (in millions): 2018 2017 Lives Acquired contracts $ 458 $ 458 0 – 9 Years Customer relationships 445 445 7 – 14 Years Trademark and trade name 40 40 15 Years Other 88 88 17 – 23 Years 1,031 1,031 Less: Accumulated amortization 619 519 Intangible assets, net $ 412 $ 512 |
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): 2019 $ 71 2020 $ 44 2021 $ 40 2022 $ 35 2023 $ 28 |
Schedule of Total Contractual Future Minimum Lease Receipts | 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 Future minimum rent payments under these lease agreements, including renewal options and rent escalation clauses, are as follows (in millions): Initial Year 2019 2020 2021 2022 2023 Thereafter Total Land and other operating leases various $ 13 $ 13 $ 12 $ 10 $ 10 $ 174 $ 232 Power plant operating lease 2000 31 — — — — — 31 Total leases $ 44 $ 13 $ 12 $ 10 $ 10 $ 174 $ 263 |
Revenue from Contracts with C_2
Revenue from Contracts with Customers (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contracts with Customers [Abstract] | |
Disaggregation of Revenue [Table Text Block] | The following tables represent a disaggregation of our revenue for the year ended December 31, 2018 by reportable segment (in millions). See Note 18 for a description of our segments. 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. |
Acquisitions, Divestitures an_2
Acquisitions, Divestitures and Discontinued Operations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Six Power Plants Disposed [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | The following table summarizes the consideration paid for Calpine Solutions as well as the preliminary determination of the identifiable assets acquired and liabilities assumed at the December 1, 2016 acquisition date (in millions): Consideration $ 1,150 Identifiable assets acquired and liabilities assumed: Assets: Current assets 141 Margin deposits and other prepaid expense 518 Derivative assets, current (1) 365 Property, plant and equipment, net 7 Intangible assets (2) 360 Goodwill 162 Long-term derivative assets (1) 359 Total assets acquired 1,912 Liabilities: Current liabilities 276 Derivative liabilities, current (1) 270 Long-term derivative liabilities (1) 216 Total liabilities assumed 762 Net assets acquired $ 1,150 ____________ (1) Consists of acquired customer and wholesale contracts which will be substantially amortized over 5 years. (2) Consists primarily of customer relationships that are being amortized over 14 years. See Note 3 for a further description of our intangible assets. |
Business Acquisition, Pro Forma Information [Table Text Block] | The following table summarizes the unaudited pro forma operating revenues and net income attributable to Calpine for the periods presented as if Calpine Solutions was acquired on January 1, 2015. The unaudited pro forma information has been prepared by adding the preliminary, unaudited historical results of Calpine Solutions, as adjusted for amortization of intangible assets and acquired contracts (using the preliminary values assigned to the net assets acquired from Calpine Solutions disclosed above) and interest expense from our 2017 First Lien Term Loan which funded a portion of the purchase price, to our results for the periods indicated below (in millions). 2016 (Unaudited) Operating revenues $ 8,324 Net income attributable to Calpine $ 105 |
Property, Plant and Equipment_2
Property, Plant and Equipment, Net (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment, Net [Abstract] | |
Property, Plant and Equipment | As of December 31, 2018 and 2017 , the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions): 2018 2017 Depreciable Lives Buildings, machinery and equipment $ 16,400 $ 16,506 1.5 – 46 Years Geothermal properties 1,501 1,494 13 – 58 Years Other 286 236 3 – 46 Years 18,187 18,236 Less: Accumulated depreciation 6,832 6,383 11,355 11,853 Land 121 117 Construction in progress 966 754 Property, plant and equipment, net $ 12,442 $ 12,724 |
Variable Interest Entities an_2
Variable Interest Entities and Unconsolidated Investments (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Variable Interest Entities and Unconsolidated Investments [Abstract] | |
Schedule of Equity Method Investments | At December 31, 2018 and 2017 , our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions): Ownership Interest as of December 31, 2018 2018 2017 Greenfield LP 50% $ 55 $ 92 Whitby 50% 15 6 Calpine Receivables 100% 6 8 Total investments in unconsolidated subsidiaries $ 76 $ 106 |
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 2018 2017 2016 2018 2017 2016 Greenfield LP $ (11 ) $ (14 ) $ (10 ) $ 48 $ 8 $ 8 Whitby (15 ) (10 ) (14 ) 5 20 13 Calpine Receivables 2 2 — — — — Total $ (24 ) $ (22 ) $ (24 ) $ 53 $ 28 $ 21 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | Debt Our debt at December 31, 2018 and 2017 , was as follows (in millions): 2018 2017 Senior Unsecured Notes $ 3,036 $ 3,417 First Lien Term Loans 2,976 2,995 First Lien Notes 2,400 2,396 Project financing, notes payable and other 1,264 1,498 CCFC Term Loan 974 984 Capital lease obligations 105 115 Corporate Revolving Facility 30 — Subtotal 10,785 11,405 Less: Current maturities 637 225 Total long-term debt $ 10,148 $ 11,180 |
Schedule of Maturities of Long-term Debt | Annual Debt Maturities Contractual annual principal repayments or maturities of debt instruments as of December 31, 2018 , are as follows (in millions): 2019 $ 642 2020 246 2021 259 2022 1,019 2023 2,535 Thereafter 6,217 Subtotal 10,918 Less: Debt issuance costs 112 Less: Discount 21 Total debt $ 10,785 |
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) 2018 2017 2018 2017 2023 Senior Unsecured Notes $ 1,227 $ 1,239 5.6 % 5.6 % 2024 Senior Unsecured Notes 599 644 5.7 5.7 2025 Senior Unsecured Notes 1,210 1,534 6.0 6.0 Total Senior Unsecured Notes $ 3,036 $ 3,417 ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs. |
Debt Instrument Redemption [Table Text Block] | Principal Repurchased Cash Paid Gain on Extinguishment of Debt (in million) 2023 Senior Unsecured Notes $ 14 $ 13 $ 1 2024 Senior Unsecured Notes 46 42 4 2025 Senior Unsecured Notes 330 300 30 Total $ 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) 2018 2017 2018 2017 2019 First Lien Term Loan $ 389 $ 389 4.9 % 4.1 % 2023 First Lien Term Loans 1,059 1,064 5.4 4.6 2024 First Lien Term Loan (2) 1,528 1,542 5.0 4.2 Total First Lien Term Loans $ 2,976 $ 2,995 ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. (2) Our 2024 First Lien Term Loan carries substantially similar terms as our 2023 First Lien Term Loans 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) 2018 2017 2018 2017 2022 First Lien Notes $ 743 $ 741 6.4 % 6.4 % 2024 First Lien Notes 486 485 6.1 6.1 2026 First Lien Notes 1,171 1,170 5.5 5.5 Total First Lien Notes $ 2,400 $ 2,396 ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. |
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) 2018 2017 2018 2017 Russell City due 2023 $ 341 $ 401 6.5 % 6.4 % Steamboat due 2025 384 414 4.5 4.7 OMEC due 2024 (2) 218 294 7.1 7.2 Los Esteros due 2023 163 191 4.7 5.3 Pasadena (3) 76 89 8.9 8.9 Bethpage Energy Center 3 due 2020-2025 (4) 53 60 7.1 7.1 Other 29 49 — — Total $ 1,264 $ 1,498 _____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. (2) On December 19, 2018, we refinanced the project debt associated with OMEC which lowered the aggregate debt balance to $220 million and extended the maturity to August 2024. In the event that the OMEC put option is exercised, the debt will become payable on November 3, 2019. See Note 7 for further information related to the OMEC put option. (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) 2018 2017 2018 2017 CCFC Term Loan $ 974 $ 984 4.9 % 4.6 % ____________ (1) Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. |
Schedule of Future Minimum Lease Payments for Capital Leases | Capital Lease Obligations The following is a schedule by year of future minimum lease payments under capital leases and a failed sale-leaseback transaction related to our Pasadena Power Plant together with the present value of the net minimum lease payments as of December 31, 2018 (in millions): Sale-Leaseback Transaction (1) Capital Lease Total 2019 $ 21 $ 19 $ 40 2020 21 19 40 2021 21 17 38 2022 16 17 33 2023 6 21 27 Thereafter 20 72 92 Total minimum lease payments 105 165 270 Less: Amount representing interest 29 60 89 Present value of net minimum lease payments $ 76 $ 105 $ 181 ____________ (1) Amounts are accounted for as a financing transaction under U.S. GAAP and are included in our project financing, notes payable and other amounts above. |
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, 2018 and 2017 (in millions): 2018 2017 Corporate Revolving Facility $ 693 $ 629 CDHI 251 244 Various project financing facilities 228 196 Other corporate facilities 193 — Total $ 1,365 $ 1,069 |
Fair Value, by Balance Sheet Grouping | The following table details the fair values and carrying values of our debt instruments at December 31, 2018 and 2017 (in millions): 2018 2017 Fair Value Carrying Fair Value Carrying Value Senior Unsecured Notes $ 2,803 $ 3,036 $ 3,294 $ 3,417 First Lien Term Loans 2,877 2,976 3,043 2,995 First Lien Notes 2,299 2,400 2,437 2,396 Project financing, notes payable and other (1) 1,209 1,188 1,439 1,409 CCFC Term Loan 938 974 1,000 984 Corporate Revolving Facility 30 30 — — Total $ 10,156 $ 10,604 $ 11,213 $ 11,201 ____________ (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, 2018 | |
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, 2018 and 2017 , by level within the fair value hierarchy: 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 Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2017 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 131 $ — $ — $ 131 Commodity instruments: Commodity exchange traded derivatives contracts 746 — — 746 Commodity forward contracts (2) — 327 265 592 Interest rate hedging instruments — 29 — 29 Effect of netting and allocation of collateral (3)(4) (746 ) (206 ) (23 ) (975 ) Total assets $ 131 $ 150 $ 242 $ 523 Liabilities: Commodity instruments: Commodity exchange traded derivatives contracts 790 — — 790 Commodity forward contracts (2) — 461 68 529 Interest rate hedging instruments — 34 — 34 Effect of netting and allocation of collateral (3)(4) (790 ) (224 ) (23 ) (1,037 ) Total liabilities $ — $ 271 $ 45 $ 316 ___________ (1) As of December 31, 2018 and 2017 , we had cash equivalents of $23 million and $21 million included in cash and cash equivalents and $145 million and $110 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 $(1) million , $48 million and nil , respectively, at December 31, 2018 . Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $44 million , $18 million and nil , respectively, at December 31, 2017 . |
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, 2018 and 2017 : 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 Quantitative Information about Level 3 Fair Value Measurements December 31, 2017 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts (1) $ 149 Discounted cash flow Market price (per MWh) $4.13 — $119.20/MWh Power Congestion Products $ 11 Discounted cash flow Market price (per MWh) $(10.54) — $9.13/MWh Natural Gas Contracts $ 34 Discounted cash flow Market price (per MMBtu) $1.62 — $13.67/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, 2018 , 2017 and 2016 (in millions): 2018 2017 2016 Balance, beginning of period $ 197 $ 416 $ (46 ) Realized and mark-to-market gains (losses): Included in net income (loss): Included in operating revenues (1) (88 ) 32 (46 ) Included in fuel and purchased energy expense (2) (45 ) 50 7 Change in collateral — (17 ) 17 Purchases, issuances and settlements: Purchases (3) 18 4 426 Issuances (2 ) (1 ) — Settlements (86 ) (179 ) (21 ) Transfers in and/or out of level 3 (4) : Transfers into level 3 (5) — (2 ) 4 Transfers out of level 3 (6) (2 ) (106 ) 75 Balance, end of period $ (8 ) $ 197 $ 416 Change in unrealized gains (losses) relating to instruments still held at end of period $ (133 ) $ 82 $ (39 ) ___________ (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) During December 2016, we had $421 million in purchases related to the acquisition of Calpine Solutions, formerly Noble Solutions. (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, 2018 , 2017 and 2016 . (5) We had nil and $(2) million in losses and $4 million in gains transferred out of level 2 into level 3 for the years ended December 31, 2018 , 2017 and 2016 , respectively. (6) We had $2 million and $104 million in gains and $(75) million in losses transferred out of level 3 into level 2 during the years ended December 31, 2018 , 2017 and 2016 , 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, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | As of December 31, 2018 and 2017 , 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 2018 2017 Power (MWh) (161 ) (119 ) Natural gas (MMBtu) 1,045 405 Environmental credits (Tonnes) 13 12 Interest rate hedging instruments $ 4,500 $ 4,600 |
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, 2018 and 2017 (in millions): 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 (2) $ 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 (2) $ 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) (2) $ (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) (2) $ (367 ) $ 227 $ (140 ) Total derivative liabilities $ (1,711 ) $ 1,268 $ (443 ) Net derivative assets (liabilities) $ (188 ) $ 47 $ (141 ) December 31, 2017 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 $ 672 $ (672 ) $ — Commodity forward contracts 361 (194 ) 167 Interest rate hedging instruments 7 — 7 Total current derivative assets (3) $ 1,040 $ (866 ) $ 174 Commodity exchange traded derivatives contracts 74 (74 ) — Commodity forward contracts 231 (32 ) 199 Interest rate hedging instruments 22 (3 ) 19 Total long-term derivative assets (3) $ 327 $ (109 ) $ 218 Total derivative assets $ 1,367 $ (975 ) $ 392 Derivative (liabilities): Commodity exchange traded derivatives contracts $ (702 ) $ 702 $ — Commodity forward contracts (389 ) 209 (180 ) Interest rate hedging instruments (17 ) — (17 ) Total current derivative (liabilities) (3) $ (1,108 ) $ 911 $ (197 ) Commodity exchange traded derivatives contracts (88 ) 88 — Commodity forward contracts (140 ) 35 (105 ) Interest rate hedging instruments (17 ) 3 (14 ) Total long-term derivative (liabilities) (3) $ (245 ) $ 126 $ (119 ) Total derivative liabilities $ (1,353 ) $ 1,037 $ (316 ) Net derivative assets (liabilities) $ 14 $ 62 $ 76 ____________ (1) At December 31, 2018 and 2017 , we had $244 million and $155 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, 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. (3) At December 31, 2017 , current and long-term derivative assets are shown net of collateral of $(8) million and $(2) million , respectively, and current and long-term derivative liabilities are shown net of collateral of $52 million and $20 million , respectively. |
Derivative Instrument by Accounting Designation | December 31, 2018 December 31, 2017 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 $ 40 $ 10 $ 26 $ 31 Total derivatives designated as cash flow hedging instruments $ 40 $ 10 $ 26 $ 31 Derivatives not designated as hedging instruments: Commodity instruments $ 262 $ 433 $ 366 $ 285 Total derivatives not designated as hedging instruments $ 262 $ 433 $ 366 $ 285 Total derivatives $ 302 $ 443 $ 392 $ 316 |
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, 2018 , 2017 and 2016 (in millions): 2018 2017 2016 Realized gain (loss) (1)(2) Commodity derivative instruments $ 193 $ 7 $ 235 Total realized gain $ 193 $ 7 $ 235 Mark-to-market gain (loss) (3) Commodity derivative instruments $ (208 ) $ (171 ) $ (1 ) Interest rate hedging instruments 3 2 2 Total mark-to-market gain (loss) $ (205 ) $ (169 ) $ 1 Total activity, net $ (12 ) $ (162 ) $ 236 ___________ (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, Calpine Solutions and North American Power. (3) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. |
Derivatives Not Designated as Hedging Instruments [Table Text Block] | 2018 2017 2016 Realized and mark-to-market gain (loss) (1) Derivatives contracts included in operating revenues (2)(3) $ (369 ) $ (69 ) $ 109 Derivatives contracts included in fuel and purchased energy expense (2)(3) 354 (95 ) 125 Interest rate hedging instruments included in interest expense 3 2 2 Total activity, net $ (12 ) $ (162 ) $ 236 ___________ (1) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and 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, Calpine Solutions and North American Power. |
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, 2018 , 2017 and 2016 (in millions): Gain (Loss) Recognized in OCI (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) (3)(4) 2018 2017 2016 2018 2017 2016 Affected Line Item on the Consolidated Statements of Operations Interest rate hedging instruments (1)(2) $ 45 $ 21 $ 41 $ (5 ) $ (43 ) $ (43 ) Interest expense Interest rate hedging instruments (1)(2) 1 5 — (1 ) (5 ) — Depreciation expense Total $ 46 $ 26 $ 41 $ (6 ) $ (48 ) $ (43 ) ____________ (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 . We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the year ended December 31, 2016 . (2) We recorded income tax expense of $5 million , $6 million and $1 million for the years ended December 31, 2018 , 2017 and 2016 , 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 $34 million , $72 million and $90 million at December 31, 2018 , 2017 and 2016 , respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million , $ 6 million and $ 8 million at December 31, 2018 , 2017 and 2016 , respectively. (4) Includes losses of $1 million , nil and $3 million that were reclassified from AOCI to interest expense for the years ended December 31, 2018 , 2017 and 2016 , respectively, where the hedged transactions became probable of not occurring. |
Use of Collateral (Tables)
Use of Collateral (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 and 2017 (in millions): 2018 2017 Margin deposits (1) $ 343 $ 221 Natural gas and power prepayments 31 23 Total margin deposits and natural gas and power prepayments with our counterparties (2) $ 374 $ 244 Letters of credit issued $ 1,166 $ 885 First priority liens under power and natural gas agreements 92 102 First priority liens under interest rate hedging instruments 10 31 Total letters of credit and first priority liens with our counterparties $ 1,268 $ 1,018 Margin deposits posted with us by our counterparties (1)(3) $ 52 $ 4 Letters of credit posted with us by our counterparties 27 30 Total margin deposits and letters of credit posted with us by our counterparties $ 79 $ 34 ___________ (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, 2018 and 2017 , $79 million and $64 million , respectively, were included in current and long-term derivative assets and liabilities, $286 million and $171 million , respectively, were included in margin deposits and other prepaid expense and $9 million and $9 million , respectively, were included in other assets on our Consolidated Balance Sheets. (3) At December 31, 2018 and 2017 , $32 million and $2 million , respectively, were included in current and long-term derivative assets and liabilities and $20 million and $2 million , respectively, were included in other current liabilities on our Consolidated Balance Sheets. |
Income Taxes Income Taxes (Tabl
Income Taxes Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 , 2017 and 2016 , are as follows (in millions): 2018 2017 2016 U.S. $ 47 $ (358 ) $ 116 International 27 27 24 Total $ 74 $ (331 ) $ 140 |
Schedule of Components of Income Tax Expense (Benefit) | The components of income tax expense from continuing operations for the years ended December 31, 2018 , 2017 and 2016 , consisted of the following (in millions): 2018 2017 2016 Current: Federal $ — $ (10 ) $ (10 ) State 20 18 14 Foreign (3 ) (14 ) 1 Total current 17 (6 ) 5 Deferred: Federal (1 ) 5 10 State (6 ) 6 27 Foreign 54 3 6 Total deferred 47 14 43 Total income tax expense $ 64 $ 8 $ 48 |
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, 2018 , 2017 and 2016 , is as follows: 2018 2017 2016 Federal statutory tax rate 21.0 % 35.0 % 35.0 % State tax expense, net of federal benefit 17.0 (6.0 ) 19.4 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 (31.7 ) (33.0 ) (25.0 ) Valuation allowance related to foreign taxes (138.3 ) 0.5 (0.1 ) Decrease in foreign NOL due to change in ownership 202.3 — — Distributions from foreign affiliates and foreign taxes 6.6 (2.0 ) (0.6 ) Change in unrecognized tax benefits (8.0 ) 5.1 (0.1 ) Disallowed compensation 7.7 (0.6 ) 0.9 Stock-based compensation (1.5 ) (0.9 ) 2.2 Equity earnings 1.4 (0.8 ) 2.0 Merger Related Fees/Expenses 12.7 — — Depletion in excess of basis (4.0 ) — — Other differences 1.3 0.3 0.6 Effective income tax rate 86.5 % (2.4 )% 34.3 % |
Schedule of Deferred Tax Assets and Liabilities | The components of deferred income taxes as of December 31, 2018 and 2017 , are as follows (in millions): 2018 2017 Deferred tax assets: NOL and credit carryforwards $ 1,595 $ 1,810 Taxes related to risk management activities and derivatives 7 20 Reorganization items and impairments 166 146 Other differences 101 28 Deferred tax assets before valuation allowance 1,869 2,004 Valuation allowance (1,000 ) (1,168 ) Total deferred tax assets 869 836 Deferred tax liabilities: Property, plant and equipment (890 ) (805 ) Total deferred tax liabilities (890 ) (805 ) Net deferred tax asset (liability) (21 ) 31 Less: Non-current deferred tax liability (22 ) (28 ) Deferred income tax asset, non-current $ 1 $ 59 |
Schedule of Income Tax Contingencies | A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2018 , 2017 and 2016 , is as follows (in millions): 2018 2017 2016 Balance, beginning of period $ (38 ) $ (59 ) $ (58 ) Increases related to prior year tax positions (7 ) — — Decreases related to prior year tax positions 17 11 1 Increases related to current year tax positions — (2 ) (2 ) Decreases related to change in tax rate of net deferred tax asset — 12 — Balance, end of period $ (28 ) $ (38 ) $ (59 ) |
Capital Structure (Tables)
Capital Structure (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Capital Structure [Abstract] | |
Schedule of Common Stock Activity | The table below summarizes our common stock activity for the years ended December 31, 2018 , 2017 and 2016 . Shares Issued Shares Held in Treasury Shares Outstanding Balance, December 31, 2015 356,755,747 (93,743 ) 356,662,004 Shares issued under Calpine Equity Incentive Plans 2,871,366 (449,079 ) 2,422,287 Share repurchase program — (22,527 ) (22,527 ) 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 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Future Minimum Rental Payments for Power Plant and Land and Other Operating Leases | 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 Future minimum rent payments under these lease agreements, including renewal options and rent escalation clauses, are as follows (in millions): Initial Year 2019 2020 2021 2022 2023 Thereafter Total Land and other operating leases various $ 13 $ 13 $ 12 $ 10 $ 10 $ 174 $ 232 Power plant operating lease 2000 31 — — — — — 31 Total leases $ 44 $ 13 $ 12 $ 10 $ 10 $ 174 $ 263 |
Schedule of Future Minimum Lease Payments for Office and Equipment Leases | Future minimum lease payments under these leases are as follows (in millions): 2019 $ 6 2020 6 2021 8 2022 8 2023 7 Thereafter 18 Total $ 53 |
Schedule Of Future Minimum Payments For Commodities | At December 31, 2018 , we had future commitments for the purchase, transportation, or storage of commodities as detailed below (in millions): 2019 $ 415 2020 172 2021 134 2022 101 2023 93 Thereafter 201 Total $ 1,116 |
Schedule of Guarantor Obligations | At December 31, 2018 , 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 2019 2020 2021 2022 2023 Thereafter Total Guarantee of subsidiary debt (1) $ 30 $ 30 $ 29 $ 24 $ 14 $ 52 $ 179 Standby letters of credit (2)(3)(4) 1,321 6 — — 38 — 1,365 Surety bonds (4)(5)(6) 12 7 — — — 76 95 Guarantee under Accounts Receivable Sales Program (7) 238 — — — — — 238 Total $ 1,601 $ 43 $ 29 $ 24 $ 52 $ 128 $ 1,877 ____________ (1) Represents Calpine Corporation guarantees of certain power plant capital leases and related interest. All guaranteed capital 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, 2018 , 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 29, 2019 . |
Segment and Significant Custo_2
Segment and Significant Customer Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 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 ) Year Ended December 31, 2016 Wholesale West Texas East Retail Consolidation and Elimination Total Total operating revenues (1) $ 1,545 $ 2,145 $ 1,657 $ 1,520 $ (151 ) $ 6,716 Commodity Margin $ 984 $ 543 $ 905 $ 172 $ — $ 2,604 Add: Mark-to-market commodity activity, net and other (2) (11 ) 12 15 (62 ) (29 ) (75 ) Less: Operating and maintenance expense 355 298 312 41 (29 ) 977 Depreciation and amortization expense 224 205 214 19 — 662 General and other administrative expense 38 56 40 6 — 140 Other operating expenses 33 8 38 — — 79 Impairment losses 13 — — — — 13 (Gain) on sale of assets, net — — (157 ) — — (157 ) (Income) from unconsolidated subsidiaries — — (24 ) — — (24 ) Income (loss) from operations 310 (12 ) 497 44 — 839 Interest expense 631 Debt modification and extinguishment costs and other (income) expense, net 49 Income before income taxes $ 159 __________ (1) Includes intersegment revenues of $488 million , $324 million and $20 million in the West, $573 million , $361 million and $81 million in Texas, $234 million , $237 million and $48 million in the East and $4 million , $4 million , $2 million in Retail for the years ended December 31, 2018 , 2017 and 2016 , respectively. (2) Includes nil , $(8) million and $(2) million of lease levelization and $104 million , $178 million and $122 million of amortization expense for the years ended December 31, 2018 , 2017 and 2016 , respectively. |
Quarterly Consolidated Financ_2
Quarterly Consolidated Financial Data (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Consolidated Financial Data (unaudited) | Quarter Ended December 31 September 30 June 30 March 31 (in millions) 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 ) 2017 Operating revenues $ 1,801 $ 2,586 $ 2,084 $ 2,281 Income (loss) from operations $ (100 ) $ 393 $ 13 $ 72 Net income (loss) attributable to Calpine $ (292 ) $ 225 $ (216 ) $ (56 ) |
Merger Agreement (Details)
Merger Agreement (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Mar. 08, 2018 | |
Business Acquisition [Line Items] | |||
Sale of Stock, Price Per Share | $ 15.25 | ||
Sale of Stock, Consideration Received on Transaction | $ 5,600 | ||
Payments for Merger Related Costs | $ 33 | $ 15 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Restricted Cash and Cash Equivalents Items [Line Items] | |||
Current | $ 167 | $ 134 | |
Non-current | 34 | 25 | |
Total | 201 | 159 | |
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | |||
Gain on Business Interruption Insurance Recovery | $ 14 | 27 | $ 24 |
Income Taxes Threshold Percentage | 50.00% | ||
Property, plant and equipment, salvage value (as a percent) | 10.00% | ||
Goodwill | $ 242 | 242 | |
Impairment losses | 10 | 41 | 13 |
Asset retirement obligations | 63 | 43 | |
Long-term Debt | 10,156 | 11,213 | |
Property, Plant and Equipment, Net | $ 12,442 | 12,724 | |
Jointly Owned Plants [Abstract] | |||
Goodwill, Purchase Accounting Adjustments | 6 | ||
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 | (167) | ||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | $ 1 | ||
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 | $ 251 | ||
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation | (114) | ||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | 4 | ||
Debt Service | |||
Restricted Cash and Cash Equivalents Items [Line Items] | |||
Current | 13 | 11 | |
Non-current | 8 | 8 | |
Total | 21 | 19 | |
Construction Major Maintenance | |||
Restricted Cash and Cash Equivalents Items [Line Items] | |||
Current | 23 | 28 | |
Non-current | 24 | 16 | |
Total | 47 | 44 | |
Security Project Insurance | |||
Restricted Cash and Cash Equivalents Items [Line Items] | |||
Current | 120 | 92 | |
Non-current | 0 | 0 | |
Total | 120 | 92 | |
Other | |||
Restricted Cash and Cash Equivalents Items [Line Items] | |||
Current | 11 | 3 | |
Non-current | 2 | 1 | |
Total | $ 13 | 4 | |
Greenfield [Member] | |||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | |||
Ownership percentage in equity method investment | 50.00% | ||
Whitby [Member] | |||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | |||
Ownership percentage in equity method investment | 50.00% | ||
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 | 28 | 13 |
Texas [Member] | |||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | |||
Impairment losses | 0 | 13 | 0 |
East [Member] | |||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | |||
Impairment losses | 10 | 0 | $ 0 |
North American Power [Member] | |||
Jointly Owned Plants [Abstract] | |||
Goodwill, Acquired During Period | $ 49 | ||
Russell City Energy [Member] | |||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | |||
Long-term Debt | 341 | ||
Property, Plant and Equipment, Net | 676 | ||
Los Esteros Project [Member] | |||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | |||
Long-term Debt | 163 | ||
Property, Plant and Equipment, Net | 439 | ||
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 | 180 | ||
Maximum [Member] | |||
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract] | |||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $ 200 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies Contractual Future Minimum Lease Receipt Table (Details) $ in Millions | Dec. 31, 2018USD ($) |
Accounting Policies [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 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies Intangible Assets by Component (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Assets, Gross | $ 1,031 | $ 1,031 | |
Finite-Lived Intangible Assets, Accumulated Amortization | 619 | 519 | |
Finite-Lived Intangible Assets, Net | 412 | 512 | |
Amortization of Intangible Assets | 100 | 175 | $ 218 |
Acquired contracts [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Assets, Gross | $ 458 | 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 | $ 88 | $ 88 | |
Other Intangible Assets [Member] | Minimum [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Asset, Useful Life | 17 years | ||
Other Intangible Assets [Member] | Maximum [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Asset, Useful Life | 23 years |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies Amortization of Intangible Assets for Future Years (Details) $ in Millions | Dec. 31, 2018USD ($) |
Schedule of Finite Lived Assets Future Amortization Expense [Abstract] | |
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | $ 71 |
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 44 |
Finite-Lived Intangible Assets, Amortization Expense, Year Three | 40 |
Finite-Lived Intangible Assets, Amortization Expense, Year Four | 35 |
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, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 9,865 | $ 8,836 | $ 6,943 | ||||||||||||
Revenues | $ 2,354 | $ 2,890 | $ 2,259 | $ 2,009 | $ 1,801 | $ 2,586 | $ 2,084 | $ 2,281 | 9,512 | [1] | 8,752 | [1] | 6,716 | [1] | |
Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 5,048 | ||||||||||||||
Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 903 | ||||||||||||||
Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 5,951 | ||||||||||||||
Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | 0 | |||||||||||||
Revenues Relating to Leases and Derivative Instruments [Member] | |||||||||||||||
Revenues | [3] | 3,561 | |||||||||||||
West [Member] | |||||||||||||||
Revenues | [1] | 1,988 | 1,881 | 1,545 | |||||||||||
West [Member] | Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,070 | ||||||||||||||
West [Member] | Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 152 | ||||||||||||||
West [Member] | Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,222 | ||||||||||||||
West [Member] | Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | 30 | |||||||||||||
Texas [Member] | |||||||||||||||
Revenues | [1] | 2,860 | 2,342 | 2,145 | |||||||||||
Texas [Member] | Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,500 | ||||||||||||||
Texas [Member] | Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 94 | ||||||||||||||
Texas [Member] | Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,594 | ||||||||||||||
Texas [Member] | Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | 34 | |||||||||||||
East [Member] | |||||||||||||||
Revenues | [1] | 1,987 | 1,658 | 1,657 | |||||||||||
East [Member] | Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 621 | ||||||||||||||
East [Member] | Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 657 | ||||||||||||||
East [Member] | Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,278 | ||||||||||||||
East [Member] | Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | 89 | |||||||||||||
Retail [Member] | |||||||||||||||
Revenues | [1] | 3,976 | $ 3,797 | $ 1,520 | |||||||||||
Retail [Member] | Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,857 | ||||||||||||||
Retail [Member] | Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||||||
Retail [Member] | Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,857 | ||||||||||||||
Retail [Member] | Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | 4 | |||||||||||||
Intersegment Eliminations [Member] | Energy and Other Products [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||||||
Intersegment Eliminations [Member] | Capacity Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||||||
Intersegment Eliminations [Member] | Revenues Relating to Physical or Executory Contracts - Third Party [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||||||
Intersegment Eliminations [Member] | Affiliate Revenue [Member] | |||||||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | [2] | $ (157) | |||||||||||||
[1] | Includes intersegment revenues of $488 million, $324 million and $20 million in the West, $573 million, $361 million and $81 million in Texas, $234 million, $237 million and $48 million in the East and $4 million, $4 million, $2 million in Retail for the years ended December 31, 2018, 2017 and 2016, respectively. | ||||||||||||||
[2] | Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine. | ||||||||||||||
[3] | Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Statements of Operations. |
Revenue from Contracts with C_4
Revenue from Contracts with Customers Performance Obligations and Contract Balances (Details) - Environmental Credits [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Deferred Revenue, Current | $ 14 | $ 15 |
Deferred Revenue, Revenue Recognized | $ 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, 2018USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 618 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
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 | $ 508 |
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 | $ 467 |
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 | $ 201 |
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 | $ 23 |
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 | $ 23 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period |
Acquisitions, Divestitures an_3
Acquisitions, Divestitures and Discontinued Operations (Textuals) (Details) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||
Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Jan. 17, 2017USD ($) | Dec. 01, 2016USD ($) | Oct. 26, 2016MW | Feb. 05, 2016USD ($)MW | ||
Business Acquisition [Line Items] | ||||||||||
Business Acquisition, Pro Forma Revenue | $ 8,324 | |||||||||
Business Acquisition, Pro Forma Net Income (Loss) | 105 | |||||||||
(Gain) on sale of power plants, net | $ 0 | $ 27 | 157 | |||||||
Calpine Solutions [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net | $ 1,150 | |||||||||
Working Capital Adjustment to Sale price | 350 | |||||||||
Recovered collateral subsequent to closing | 250 | |||||||||
Expected recovery through collateral synergies | $ 200 | |||||||||
Number of States in which Entity Operates | 20 | |||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets | $ 141 | |||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets | 518 | |||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Derivative assets | [1] | 365 | ||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 7 | |||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles | [2] | 360 | ||||||||
Business Acquisition, Goodwill, Expected Tax Deductible Amount | 162 | |||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Long-term derivative asset | [1] | 359 | ||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 1,912 | |||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities | 276 | |||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Derivative liabilities, current | [1] | 270 | ||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Long-term derivative liabilities | [1] | 216 | ||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | $ 762 | |||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | $ 800 | $ 800 | ||||||||
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 | |||||||||
Granite Ridge Energy Center [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Summer peaking capacity | MW | 695 | |||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | $ 500 | |||||||||
Power generation capacity | MW | 745 | |||||||||
Osprey Energy Center [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proceeds from Sale of Productive Assets | $ 166 | |||||||||
(Gain) on sale of power plants, net | $ 27 | |||||||||
Mankato [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proceeds from Sale of Productive Assets | 396 | |||||||||
Gain (Loss) on Sale of Assets and Asset Impairment Charges | $ 157 | |||||||||
Power generation capacity | MW | 375 | |||||||||
Expansion generation capacity | MW | 345 | |||||||||
Acquired contracts [Member] | Calpine Solutions [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Finite-Lived Intangible Asset, Useful Life | 5 years | |||||||||
Customer Relationships [Member] | Calpine Solutions [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Finite-Lived Intangible Asset, Useful Life | 14 years | |||||||||
[1] | Consists of acquired customer and wholesale contracts which will be substantially amortized over 5 years. | |||||||||
[2] | Consists primarily of customer relationships that are being amortized over 14 years. See Note 3 for a further description of our intangible assets. |
Property, Plant and Equipment_3
Property, Plant and Equipment, Net (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |||
Buildings, machinery and equipment | $ 16,400 | $ 16,506 | |
Geothermal properties | 1,501 | 1,494 | |
Other | 286 | 236 | |
Property, Plant and Equipment, Gross | 18,187 | 18,236 | |
Less: Accumulated depreciation | 6,832 | 6,383 | |
Property, Plant and Equipment, Gross, Less Accumulated Depreciation | 11,355 | 11,853 | |
Land | 121 | 117 | |
Construction in progress | 966 | 754 | |
Property, plant and equipment, net | 12,442 | 12,724 | |
Depreciation | 684 | 638 | $ 628 |
Interest Costs, Capitalized During Period | $ 29 | $ 26 | $ 21 |
Componentized Balance [Member] [Member] | Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Estimated Useful Lives | 6 years | ||
Componentized Balance [Member] [Member] | Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Estimated Useful Lives | 25 years | ||
Rotable Parts [Member] | Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Estimated Useful Lives | 1 year 6 months | ||
Rotable Parts [Member] | Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Estimated Useful Lives | 12 years | ||
Building, Machinery and Equipment, Gross [Member] | Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Estimated Useful Lives | 46 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 | 46 years | ||
Service Life [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation | $ (24) |
Variable Interest Entities an_3
Variable Interest Entities and Unconsolidated Investments (Unconsolidated VIEs) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Equity Method Investments Included on Balance Sheet [Abstract] | ||
Equity Method Investments | $ 76 | $ 106 |
Greenfield [Member] | ||
Equity Method Investments Included on Balance Sheet [Abstract] | ||
Equity Method Investments | $ 55 | 92 |
Equity Method Investment, Ownership Percentage | 50.00% | |
Whitby [Member] | ||
Equity Method Investments Included on Balance Sheet [Abstract] | ||
Equity Method Investments | $ 15 | 6 |
Equity Method Investment, Ownership Percentage | 50.00% | |
Calpine Receivables [Member] | ||
Equity Method Investments Included on Balance Sheet [Abstract] | ||
Equity Method Investments | $ 6 | $ 8 |
Equity Method Investment, Ownership Percentage | 100.00% |
Variable Interest Entities an_4
Variable Interest Entities and Unconsolidated Investments (Unconsolidated Investements) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items] | |||
(Income) from unconsolidated subsidiaries | $ (24) | $ (22) | $ (24) |
Distributions from Equity Method Investments | 53 | 28 | 21 |
Greenfield [Member] | |||
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items] | |||
(Income) from unconsolidated subsidiaries | (11) | (14) | (10) |
Distributions from Equity Method Investments | 48 | 8 | 8 |
Whitby [Member] | |||
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items] | |||
(Income) from unconsolidated subsidiaries | (15) | (10) | (14) |
Distributions from Equity Method Investments | 5 | 20 | 13 |
Calpine Receivables [Member] | |||
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items] | |||
(Income) from unconsolidated subsidiaries | 2 | 2 | 0 |
Distributions from Equity Method Investments | $ 0 | $ 0 | $ 0 |
Variable Interest Entities an_5
Variable Interest Entities and Unconsolidated Investments (VIE Textuals) (Details) | 12 Months Ended | |||
Dec. 31, 2018USD ($)yrMW | Dec. 31, 2017USD ($)MW | Dec. 31, 2016USD ($) | ||
Schedule of Equity Method Investments [Line Items] | ||||
Proceeds from sale of power plants and other(2) | [1] | $ 11,000,000 | $ 162,000,000 | $ 179,000,000 |
Variable Interest Entity, Financial or Other Support, Amount | 0 | 0 | $ 115,000,000 | |
Equity Method Investment, Summarized Financial Information, Debt | 301,000,000 | 256,000,000 | ||
Prorata Share of Equity Method Investment, Summarized Financial Information, Debt | 151,000,000 | 128,000,000 | ||
Long-term Debt | 10,156,000,000 | $ 11,213,000,000 | ||
Put Option [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Proceeds from sale of power plants and other(2) | 280,000,000 | |||
Call Option [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Proceeds from sale of power plants and other(2) | $ 377,000,000 | |||
Russell City Energy [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Minority Interest Ownership Percentage By Noncontrolling Third Party Owners | 25.00% | |||
Equity Method Investment, Ownership Percentage | 75.00% | |||
Variable Interest Entity, Primary Beneficiary [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Power generation capacity | MW | 7,880 | 7,880 | ||
Inland Empire Energy Center [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Power generation capacity | MW | 775 | |||
Put Option Exercise Period | yr | 2,025 | |||
Minimum [Member] | Inland Empire Energy Center [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Call Option Exercise Period | yr | 2,017 | |||
Maximum [Member] | Inland Empire Energy Center [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Call Option Exercise Period | yr | 2,024 | |||
Calpine Receivables [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount | $ 44,000,000 | |||
Equity Method Investment, Ownership Percentage | 100.00% | |||
Greenfield [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Power generation capacity | MW | 1,038 | |||
Equity Method Investment, Ownership Percentage | 50.00% | |||
Whitby [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Power generation capacity | MW | 50 | |||
Equity Method Investment, Ownership Percentage | 50.00% | |||
OMEC [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Debt Instrument, Face Amount | $ 220,000,000 | |||
Long-term Debt | [2] | $ 218,000,000 | $ 294,000,000 | |
[1] | On October 26, 2016, we completed the sale of Mankato Power Plant for $407 million, including working capital and other adjustments. We received net proceeds of $164 million after the non-cash reduction of Steamboat project debt of $243 million as the funds were provided directly to the lender in conjunction with the sale of the power plant. | |||
[2] | On December 19, 2018, we refinanced the project debt associated with OMEC which lowered the aggregate debt balance to $220 million and extended the maturity to August 2024. In the event that the OMEC put option is exercised, the debt will become payable on November 3, 2019. See Note 7 for further information related to the OMEC put option. |
Debt (Debt) (Details)
Debt (Debt) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | $ 10,785 | $ 11,405 |
Debt, current portion | 637 | 225 |
Debt, net of current portion | 10,148 | 11,180 |
Unsecured Debt [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | 3,036 | 3,417 |
Loans Payable [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | 2,976 | 2,995 |
Corporate Debt Securities [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | 2,400 | 2,396 |
Notes Payable, Other Payables [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | 1,264 | 1,498 |
Secured Debt [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | 974 | 984 |
Capital Lease Obligations [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | 105 | 115 |
Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | $ 30 | $ 0 |
Debt (Annual Debt Marturities)
Debt (Annual Debt Marturities) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Long-term Debt, Fiscal Year Maturity [Abstract] | ||
2017 | $ 642 | |
2018 | 246 | |
2019 | 259 | |
2020 | 1,019 | |
2021 | 2,535 | |
Thereafter | 6,217 | |
Total debt, gross | 10,918 | |
Debt Issuance Costs, Net | 112 | |
Less: Discount | 21 | |
Debt and Capital Lease Obligations | $ 10,785 | $ 11,405 |
Debt Senior Unsecured Notes (De
Debt Senior Unsecured Notes (Details) - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2015 | Sep. 30, 2014 | ||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 10,156 | $ 11,213 | ||||
Debt Issuance Costs, Net | 112 | |||||
Gains (Losses) on Extinguishment of Debt | 28 | (38) | $ (25) | |||
Senior Unsecured Notes 2023 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 1,227 | $ 1,239 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 5.60% | 5.60% | |||
Debt Instrument, Face Amount | $ 1,250 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.375% | |||||
Gains (Losses) on Extinguishment of Debt | $ 1 | |||||
Senior Unsecured Notes 2024 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 599 | $ 644 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 5.70% | 5.70% | |||
Debt Instrument, Face Amount | $ 650 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | |||||
Gains (Losses) on Extinguishment of Debt | $ 4 | |||||
Senior Unsecured Notes 2025 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 1,210 | $ 1,534 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 6.00% | 6.00% | |||
Debt Instrument, Face Amount | $ 1,550 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.75% | |||||
Gains (Losses) on Extinguishment of Debt | $ 30 | |||||
Unsecured Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | 3,036 | $ 3,417 | ||||
Gains (Losses) on Extinguishment of Debt | $ 35 | |||||
[1] | Our weighted average interest rate calculation includes the amortization of debt issuance costs. |
Debt Debt Repurchases (Details)
Debt Debt Repurchases (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Instrument, Redemption [Line Items] | |||
Gains (Losses) on Extinguishment of Debt | $ 28 | $ (38) | $ (25) |
Senior Unsecured Notes 2023 [Member] | |||
Debt Instrument, Redemption [Line Items] | |||
Debt Instrument, Repurchased Face Amount | 14 | ||
Debt Instrument, Repurchase Amount | 13 | ||
Gains (Losses) on Extinguishment of Debt | 1 | ||
Unsecured Debt [Member] | |||
Debt Instrument, Redemption [Line Items] | |||
Debt Instrument, Repurchased Face Amount | 390 | ||
Debt Instrument, Repurchase Amount | 355 | ||
Gains (Losses) on Extinguishment of Debt | 35 | ||
Write off of Deferred Debt Issuance Cost | 3 | ||
Senior Unsecured Notes 2024 [Member] | |||
Debt Instrument, Redemption [Line Items] | |||
Debt Instrument, Repurchased Face Amount | 46 | ||
Debt Instrument, Repurchase Amount | 42 | ||
Gains (Losses) on Extinguishment of Debt | 4 | ||
Senior Unsecured Notes 2025 [Member] | |||
Debt Instrument, Redemption [Line Items] | |||
Debt Instrument, Repurchased Face Amount | 330 | ||
Debt Instrument, Repurchase Amount | 300 | ||
Gains (Losses) on Extinguishment of Debt | $ 30 |
Debt Debt (First Lien Term Loan
Debt Debt (First Lien Term Loans) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Mar. 31, 2017 | Jun. 30, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 10,156 | $ 11,213 | ||||
Debt Issuance Costs, Net | 112 | |||||
Gains (Losses) on Extinguishment of Debt | 28 | (38) | $ (25) | |||
2017 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Percentage of principal amount of Term Loan to be paid quarterly | 0.25% | |||||
First Lien Term Loan 2019 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 389 | $ 389 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 4.90% | 4.10% | |||
2023 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 1,059 | $ 1,064 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 5.40% | 4.60% | |||
New 2023 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Face Amount | $ 562 | |||||
Debt Instrument Unamortized Discount Percent | 1.00% | |||||
Debt Issuance Costs, Net | $ 11 | |||||
2024 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | [2] | $ 1,528 | $ 1,542 | |||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 5.00% | 4.20% | |||
Loans Payable [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 2,976 | $ 2,995 | ||||
2019 and 2020 First Lien Term Loans [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Gains (Losses) on Extinguishment of Debt | $ (15) | |||||
New 2019 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Face Amount | $ 400 | |||||
Percentage of principal amount of Term Loan to be paid quarterly | 0.25% | |||||
Debt Instrument Unamortized Discount Percent | 1.00% | |||||
Debt Issuance Costs, Net | $ 8 | |||||
Federal Funds Effective Rate [Member] | New 2023 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | |||||
Federal Funds Effective Rate [Member] | New 2019 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 2023 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] | New 2019 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 2023 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 2.00% | |||||
Prime Rate Or The Eurodollar Rate For a One Month Interest Period [Member] | New 2019 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 0.75% | |||||
London Interbank Offered Rate (LIBOR) [Member] | New 2023 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 2.75% | |||||
London Interbank Offered Rate (LIBOR) [Member] | New 2019 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 1.75% | |||||
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | New 2023 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] | New 2019 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 carries substantially similar terms as our 2023 First Lien Term Loans as discussed below. |
Debt Debt (First Lien Notes) (D
Debt Debt (First Lien Notes) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | ||
Debt Instrument [Line Items] | ||||||
Gains (Losses) on Extinguishment of Debt | $ 28 | $ (38) | $ (25) | |||
Long-term Debt | 10,156 | 11,213 | ||||
Debt Issuance Costs, Net | 112 | |||||
Long-term Debt, Gross | 10,918 | |||||
2022 First Lien Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 743 | $ 741 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 6.40% | 6.40% | |||
New 2019 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Face Amount | $ 400 | |||||
Debt Issuance Costs, Net | $ 8 | |||||
2024 First Lien Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 486 | $ 485 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 6.10% | 6.10% | |||
2026 First Lien Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Face Amount | $ 560 | $ 625 | ||||
Long-term Debt | $ 1,171 | $ 1,170 | ||||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 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 | $ 2,400 | $ 2,396 | ||||
London Interbank Offered Rate (LIBOR) [Member] | New 2019 First Lien Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 1.75% | |||||
[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, 2018 | Dec. 31, 2017 | |
Debt Instrument [Line Items] | |||
Long-term Debt | $ 10,156 | $ 11,213 | |
Russell City Project [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 341 | $ 401 | |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 6.50% | 6.40% |
Steamboat [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 384 | $ 414 | |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 4.50% | 4.70% |
OMEC [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | [2] | $ 218 | $ 294 |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 7.10% | 7.20% |
Los Esteros Project [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 163 | $ 191 | |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 4.70% | 5.30% |
Pasadena [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | [3] | $ 76 | $ 89 |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 8.90% | 8.90% |
Bethpage [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | [4] | $ 53 | $ 60 |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 7.10% | 7.10% |
Other Debt Obligations [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 29 | $ 49 | |
Debt Instrument, Interest Rate, Effective Percentage | [1] | 0.00% | 0.00% |
Project Financing Total [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 1,264 | $ 1,498 | |
[1] | Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. | ||
[2] | On December 19, 2018, we refinanced the project debt associated with OMEC which lowered the aggregate debt balance to $220 million and extended the maturity to August 2024. In the event that the OMEC put option is exercised, the debt will become payable on November 3, 2019. See Note 7 for further information related to the OMEC put option. | ||
[3] | Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP. | ||
[4] | Represents a weighted average of first and second lien loans for the weighted average effective interest rates. |
Debt CCFC Term Loans (Details)
Debt CCFC Term Loans (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Debt Instrument [Line Items] | |||||
Debt Issuance Costs, Net | $ 112 | ||||
Long-term Debt | $ 11,213 | 10,156 | $ 11,213 | ||
Gains (Losses) on Extinguishment of Debt | 28 | (38) | $ (25) | ||
Secured Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Debt | $ 984 | $ 974 | $ 984 | ||
Debt Instrument, Interest Rate, Effective Percentage | [1] | 4.60% | 4.90% | 4.60% | |
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 | 1.50% | ||||
London Interbank Offered Rate (LIBOR) [Member] | New CCFC Term Loans [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 2.50% | ||||
[1] | Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. |
Debt (Capital Lease Obligations
Debt (Capital Lease Obligations) (Details) $ in Millions | Dec. 31, 2018USD ($) | |
Minimum Lease Payments, Sale Leaseback Transactions, Fiscal Year Maturity [Abstract] | ||
Minimum Lease Payments, Sale Leaseback Transactions, within One Year | $ 21 | [1] |
Minimum Lease Payments, Sale Leaseback Transactions, within Two Years | 21 | [1] |
Minimum Lease Payments, Sale Leaseback Transactions, within Three Years | 21 | [1] |
Minimum Lease Payments, Sale Leaseback Transactions, within Four Years | 16 | [1] |
Minimum Lease Payments, Sale Leaseback Transactions, within Five Years | 6 | [1] |
Minimum Lease Payments, Sale Leaseback Transactions, Thereafter | 20 | [1] |
Minimum Lease Payments, Sale Leaseback Transactions | 105 | [1] |
Interest Portion of Minimum Lease Payments, Sale Leaseback Transactions | 29 | [1] |
Present Value of Future Minimum Lease Payments, Sale Leaseback Transactions | 76 | [1] |
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | ||
Capital Leases, Future Minimum Payments Due, Current | 19 | |
Capital Leases, Future Minimum Payments Due in Two Years | 19 | |
Capital Leases, Future Minimum Payments Due in Three Years | 17 | |
Capital Leases, Future Minimum Payments Due in Four Years | 17 | |
Capital Leases, Future Minimum Payments Due in Five Years | 21 | |
Capital Leases, Future Minimum Payments Due Thereafter | 72 | |
Capital Leases, Future Minimum Payments Due | 165 | |
Capital Leases, Future Minimum Payments, Interest Included in Payments | 60 | |
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments | 105 | |
Total Leases Future Minimum Payments [Abstract] | ||
Total Leases, Future Minimum Payments Due, Current | 40 | |
Total Leases, Future Minimum Payments Due in Two Years | 40 | |
Total Leases, Future Minimum Payments Due in Three Years | 38 | |
Total Leases, Future Minimum Payments Due in Four Years | 33 | |
Total Leases, Future Minimum Payments Due in Five Years | 27 | |
Total Leases, Future Minimum Payments Due Thereafter | 92 | |
Total Leases, Future Minimum Payments Due | 270 | |
Total Leases, Future Minimum Payments, Interest Included in Payments | 89 | |
Total Leases, Future Minimum Payments, Present Value of Net Minimum Payments | $ 181 | |
[1] | Amounts are accounted for as a financing transaction under U.S. GAAP and are included in our project financing, notes payable and other amounts above. |
Debt (Corporate Revolving Facil
Debt (Corporate Revolving Facility and other Letters of Credit Facilities) (Details) - USD ($) $ in Millions | 3 Months Ended | |||
Jun. 30, 2018 | Dec. 31, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | |
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | $ 1,365 | $ 1,069 | ||
Amendment No. 8 [Member] | Revolving Credit Facility [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Line of Credit Facility, Increase (Decrease), Net | $ 220 | |||
Revolving Credit Facility [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | 693 | 629 | ||
Revolving Credit Facility [Member] | Amendment No. 6 [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,470 | |||
Total Letter of Credit Sublimit | $ 1,150 | |||
Standby Letters of Credit [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | 251 | 244 | ||
Various Project Financing Facilities [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | 228 | 196 | ||
Other Corporate Facilities [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | 193 | $ 0 | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 200 |
Debt (Fair Value of Debt) (Deta
Debt (Fair Value of Debt) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | $ 10,156 | $ 11,213 | |
Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 10,604 | 11,201 | |
Unsecured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 3,036 | 3,417 | |
Unsecured Debt [Member] | Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 3,036 | 3,417 | |
Loans Payable [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,976 | 2,995 | |
Loans Payable [Member] | Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,976 | 2,995 | |
Corporate Debt Securities [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,400 | 2,396 | |
Corporate Debt Securities [Member] | Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,400 | 2,396 | |
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] | 1,188 | 1,409 |
Secured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 974 | 984 | |
Secured Debt [Member] | Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 974 | 984 | |
Revolving Credit Facility [Member] | Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 30 | 0 | |
Fair Value, Inputs, Level 2 [Member] | Unsecured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,803 | 3,294 | |
Fair Value, Inputs, Level 2 [Member] | Loans Payable [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,877 | 3,043 | |
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,299 | 2,437 | |
Fair Value, Inputs, Level 2 [Member] | Secured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 938 | 1,000 | |
Fair Value, Inputs, Level 2 [Member] | Revolving Credit Facility [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 30 | 0 | |
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] | $ 1,209 | $ 1,439 |
[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 | 3 Months Ended | 12 Months Ended | |||||
Jun. 30, 2018 | Jun. 30, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Apr. 11, 2018 | Mar. 31, 2018 | |
Debt Instrument [Line Items] | |||||||
Maximum Remaining Lease Term | 33 years | ||||||
Lease Assets, Historical Cost | $ 715 | $ 737 | |||||
Lease Assets, Accumulated Depreciation | 353 | 349 | |||||
Gains (Losses) on Extinguishment of Debt | $ 28 | (38) | $ (25) | ||||
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% | ||||||
New 2023 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Face Amount | $ 562 | ||||||
CDHI [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Letter of Credit Total | $ 300 | ||||||
2026 First Lien Notes [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Face Amount | $ 625 | 560 | |||||
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 | ||||||
Prime Rate Or The Eurodollar Rate For a One Month Interest Period [Member] | New 2023 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 2.00% | ||||||
Federal Funds Effective Rate [Member] | Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | ||||||
Federal Funds Effective Rate [Member] | New 2023 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 2023 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | ||||||
CDHI [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Future Line of Credit Facility Maximum Borrowing Capacity | $ 125 | ||||||
Other Corporate Facilities [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Maximum Borrowing Capacity | 200 | ||||||
Other Corporate Facilities [Member] | Goldman Sachs [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Maximum Borrowing Capacity | 150 | ||||||
Other Corporate Facilities [Member] | Citi Bank [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 50 | ||||||
Short Term Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 300 | ||||||
Amendment No. 8 [Member] | Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Increase (Decrease), Net | $ 220 | ||||||
Revolving Credit Facility [Member] | Amendment No. 7 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Total Letter of Credit Sublimit | $ 1,300 | ||||||
Incremental Revolving Facilities | 500 | ||||||
Revolving Credit Facility [Member] | Amendment No. 8 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Maximum Borrowing Capacity | 1,690 | ||||||
Revolving Credit Facility [Member] | Amendment No. 6 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,470 | ||||||
Total Letter of Credit Sublimit | $ 1,150 | ||||||
Future Line of Credit Facility Maximum Borrowing Capacity | $ 1,300 |
Assets and Liabilities with R_3
Assets and Liabilities with Recurring Fair Value Measurements (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and Cash Equivalents, Fair Value Disclosure | [1] | $ 168 | $ 131 |
Derivative Asset | [2] | 302 | 392 |
Effect of Netting and Allocation of Collateral, Asset | [3],[4] | (1,221) | (975) |
Margin Deposit Assets | [5] | 343 | 221 |
Assets, Fair Value Disclosure | 470 | 523 | |
Derivative Liability | [2] | 443 | 316 |
Effect of Netting and Allocation of Collateral, Liability | [3],[4] | (1,268) | (1,037) |
Margin deposits posted with us by our counterparties | [5],[6] | 52 | 4 |
Liabilities, Fair Value Disclosure | 443 | 316 | |
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] | 168 | 131 |
Effect of Netting and Allocation of Collateral, Asset | [3],[4] | (933) | (746) |
Assets, Fair Value Disclosure | 168 | 131 | |
Effect of Netting and Allocation of Collateral, Liability | [3],[4] | (932) | (790) |
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] | (262) | (206) |
Assets, Fair Value Disclosure | 116 | 150 | |
Effect of Netting and Allocation of Collateral, Liability | [3],[4] | (310) | (224) |
Liabilities, Fair Value Disclosure | 249 | 271 | |
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] | (26) | (23) |
Assets, Fair Value Disclosure | 186 | 242 | |
Effect of Netting and Allocation of Collateral, Liability | [3],[4] | (26) | (23) |
Liabilities, Fair Value Disclosure | 194 | 45 | |
Forward Contracts [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | [7] | 550 | 592 |
Derivative Liability | [7] | 769 | 529 |
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] | 338 | 327 |
Derivative Liability | [7] | 549 | 461 |
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] | 212 | 265 |
Derivative Liability | [7] | 220 | 68 |
Future [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | 933 | 746 | |
Derivative Liability | 932 | 790 | |
Future [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset | 933 | 746 | |
Derivative Liability | 932 | 790 | |
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 | 40 | 29 | |
Derivative Liability | 10 | 34 | |
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 | 40 | 29 | |
Derivative Liability | 10 | 34 | |
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, 2018 and 2017, we had cash equivalents of $23 million and $21 million included in cash and cash equivalents and $145 million and $110 million included in restricted cash, respectively. | ||
[2] | At December 31, 2018 and 2017, we had $244 million and $155 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 $(1) million, $48 million and nil, respectively, at December 31, 2018. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $44 million, $18 million and nil, respectively, at December 31, 2017. | ||
[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, 2018 and 2017, $32 million and $2 million, respectively, were included in current and long-term derivative assets and liabilities and $20 million and $2 million, respectively, were included in other current liabilities on our Consolidated Balance Sheets. | ||
[7] | Includes OTC swaps and options. |
Assets and Liabilities with R_4
Assets and Liabilities with Recurring Fair Value Measurements Quantitative Information about Level 3 Fair Value Measurements (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 | |
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Derivative, Fair Value, Net | [1] | $ (141,000,000) | $ 76,000,000 |
Physical Power [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Derivative, Fair Value, Net | 36,000,000 | 149,000,000 | |
Physical Power [Member] | Minimum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | 2.12 | 4.13 | |
Physical Power [Member] | Maximum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | 227.98 | 119.20 | |
Natural Gas [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Derivative, Fair Value, Net | (73,000,000) | 34,000,000 | |
Natural Gas [Member] | Minimum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | 0.75 | 1.62 | |
Natural Gas [Member] | Maximum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | 8.87 | 13.67 | |
Power Congestion Products [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Derivative, Fair Value, Net | 26,000,000 | 11,000,000 | |
Power Congestion Products [Member] | Minimum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | (11.71) | (10.54) | |
Power Congestion Products [Member] | Maximum [Member] | |||
Quantitative Information about Level 3 fair Value Measurements [Line Items] | |||
Fair Value Inputs Quantitative Information | $ 11.88 | $ 9.13 | |
[1] | At December 31, 2018 and 2017, we had $244 million and $155 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Balance Sheets primarily related to initial margin requirements. |
Assets and Liabilities with R_5
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Fair Value Measurement [Domain] | ||||
Fair Value Disclosures [Abstract] | ||||
Cash and Cash Equivalents, at Carrying Value | $ 23 | $ 21 | ||
Cash Equivalents Included In Restricted Cash, Fair Value Disclosure | 145 | 110 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | 197 | 416 | $ (46) | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Change in Unrealized Gain (Loss) | (133) | 82 | (39) | |
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount | 0 | 0 | 0 | |
Included in operating revenues | [1] | (88) | 32 | (46) |
Included in fuel and purchased energy expense | [2] | (45) | 50 | 7 |
Amount of Change in Collateral of Financial Instruments Classified as Derivative Asset (Liability) | 0 | (17) | 17 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases | [3] | 18 | 4 | 426 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Issues | (2) | (1) | 0 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements | (86) | (179) | (21) | |
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount | 0 | 0 | 0 | |
Transfers into level 3 | [4],[5] | 0 | 2 | (4) |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | [5],[6] | 2 | 106 | (75) |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | (8) | 197 | 416 | |
Cash and Cash Equivalents, at Carrying Value | 205 | 284 | ||
Cash Equivalents Included In Restricted Cash, Fair Value Disclosure | 201 | 159 | ||
Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value Disclosures [Abstract] | ||||
Derivative, Collateral, Right to Reclaim Cash, Net | (1) | 44 | ||
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 | 2 | 104 | (75) | |
Fair Value Disclosures [Abstract] | ||||
Derivative, Collateral, Right to Reclaim Cash, Net | 48 | 18 | ||
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 | |||
Calpine Solutions [Member] | ||||
Purchases, issuances and settlements: | ||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases | $ 421 | |||
[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] | During December 2016, we had $421 million in purchases related to the acquisition of Calpine Solutions, formerly Noble Solutions. | |||
[4] | We had nil and $(2) million in losses and $4 million in gains transferred out of level 2 into level 3 for the years ended December 31, 2018, 2017 and 2016, respectively. | |||
[5] | 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, 2018, 2017 and 2016. | |||
[6] | We had $2 million and $104 million in gains and $(75) million in losses transferred out of level 3 into level 2 during the years ended December 31, 2018, 2017 and 2016, 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 Millions | 12 Months Ended | |
Dec. 31, 2018USD ($)MMBTUMWht | Dec. 31, 2017USD ($)MMBTUMWht | |
Natural Gas [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | (1,045) | (405) |
Environmental Credits [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Mass | t | 13 | 12 |
Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional Amount | $ | $ 4,500 | $ 4,600 |
Short [Member] | Power [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | (161) | (119) |
Derivative Instruments (Detai_2
Derivative Instruments (Details 2) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | |
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | [1] | $ 302 | $ 392 |
Derivative Liability | [1] | 443 | 316 |
Designated as Hedging Instrument [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | 40 | 26 | |
Derivative Liability | 10 | 31 | |
Not Designated as Hedging Instrument [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | 262 | 366 | |
Derivative Liability | 433 | 285 | |
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | 262 | 366 | |
Derivative Liability | 433 | 285 | |
Interest Rate Contract [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | 40 | 29 | |
Derivative Liability | 10 | 34 | |
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Asset | 40 | 26 | |
Derivative Liability | $ 10 | $ 31 | |
[1] | At December 31, 2018 and 2017, we had $244 million and $155 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Balance Sheets primarily related to initial margin requirements. |
Derivative Instruments (Detai_3
Derivative Instruments (Details 3) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on Sale of Derivatives | [1],[2] | $ 193 | $ 7 | $ 235 |
Unrealized Gain (Loss) on Derivatives | [3] | (205) | (169) | 1 |
Gain (Loss) on Derivative Instruments, Net, Pretax | [4] | (12) | (162) | 236 |
Energy Related Derivative [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on Sale of Derivatives | [1],[2] | 193 | 7 | 235 |
Unrealized Gain (Loss) on Derivatives | [3] | (208) | (171) | (1) |
Interest Rate Contract [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized Gain (Loss) on Derivatives | [3] | 3 | 2 | 2 |
Sales [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on Derivative Instruments, Net, Pretax | [4],[5],[6] | (369) | (69) | 109 |
Cost of Sales [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on Derivative Instruments, Net, Pretax | [4],[5],[6] | 354 | (95) | 125 |
Interest Expense [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on Derivative Instruments, Net, Pretax | $ 3 | $ 2 | $ 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, Calpine Solutions and North American Power. | |||
[3] | In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and 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 hedge ineffectiveness and 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, Calpine Solutions and North American Power. |
Derivative Instruments (Detai_4
Derivative Instruments (Details 4) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss) | $ (6) | $ (48) | $ (43) | |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax | 46 | 26 | 41 | |
Interest Rate Contract [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax | [1],[2] | 45 | 21 | 41 |
Depreciation expense [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax | [1],[2] | 1 | 5 | 0 |
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) | (6) | (48) | (43) | |
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] | (5) | (43) | (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) | $ (5) | $ 0 |
[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. We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the year ended December 31, 2016. | |||
[2] | We recorded income tax expense of $5 million, $6 million and $1 million for the years ended December 31, 2018, 2017 and 2016, 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 $34 million, $72 million and $90 million at December 31, 2018, 2017 and 2016, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million, $6 million and $8 million at December 31, 2018, 2017 and 2016, respectively. | |||
[4] | Includes losses of $1 million, nil and $3 million that were reclassified from AOCI to interest expense for the years ended December 31, 2018, 2017 and 2016, respectively, where the hedged transactions became probable of not occurring. |
Derivative Instruments (Detail
Derivative Instruments (Detail 5) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | |||
Derivative [Line Items] | |||||
Derivative, Collateral, Right to Reclaim Cash | $ 244 | $ 155 | |||
Net derivative assets (liabilities) | [1] | (141) | 76 | ||
Derivative Asset, Current | [1] | 142 | [2] | 174 | [3] |
Derivative Asset, Noncurrent | [1] | 160 | [2] | 218 | [3] |
Derivative Asset | [1] | 302 | 392 | ||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (188) | (14) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 47 | 62 | |||
Derivative Liability, Current | [1] | (303) | [2] | (197) | [3] |
Derivative Liability, Noncurrent | [1] | (140) | [2] | (119) | [3] |
Derivative Liability | [1] | (443) | (316) | ||
Future [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Current | [1] | 0 | 0 | ||
Derivative Asset, Noncurrent | [1] | 0 | 0 | ||
Derivative Asset | 933 | 746 | |||
Derivative Liability, Current | [1] | 0 | 0 | ||
Derivative Liability, Noncurrent | [1] | 0 | 0 | ||
Derivative Liability | (932) | (790) | |||
Interest Rate Contract [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Current | [1] | 30 | 7 | ||
Derivative Asset, Noncurrent | [1] | 10 | 19 | ||
Derivative Asset | 40 | 29 | |||
Derivative Liability, Current | [1] | (4) | (17) | ||
Derivative Liability, Noncurrent | [1] | (6) | (14) | ||
Derivative Liability | (10) | (34) | |||
Forward Contracts [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Current | [1] | 112 | 167 | ||
Derivative Asset, Noncurrent | [1] | 150 | 199 | ||
Derivative Asset | [4] | 550 | 592 | ||
Derivative Liability, Current | [1] | (299) | (180) | ||
Derivative Liability, Noncurrent | [1] | (134) | (105) | ||
Derivative Liability | [4] | (769) | (529) | ||
Derivative Assets, Current [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 1,191 | [2] | 1,040 | [3] | |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (1,049) | [2] | (866) | [3] | |
Derivative Assets, Current [Member] | Future [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 820 | 672 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (820) | (672) | |||
Derivative Assets, Current [Member] | Interest Rate Contract [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 30 | 7 | |||
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 | 341 | 361 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (229) | (194) | |||
Derivative Assets, Non-current [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 332 | [2] | 327 | [3] | |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (172) | [2] | (109) | [3] | |
Derivative Assets, Non-current [Member] | Future [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 113 | 74 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (113) | (74) | |||
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 | 22 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 0 | (3) | |||
Derivative Assets, Non-current [Member] | Forward Contracts [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 209 | 231 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (59) | (32) | |||
Derivative Liabilities, Current [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (1,344) | [2] | (1,108) | [3] | |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 1,041 | [2] | 911 | [3] | |
Derivative Liabilities, Current [Member] | Future [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (764) | (702) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 764 | 702 | |||
Derivative Liabilities, Current [Member] | Interest Rate Contract [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (4) | (17) | |||
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 | (576) | (389) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 277 | 209 | |||
Derivative Liabilities, Non-current [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (367) | [2] | (245) | [3] | |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 227 | [2] | 126 | [3] | |
Derivative Liabilities, Non-current [Member] | Future [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (168) | (88) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 168 | 88 | |||
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 | (6) | (17) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 0 | 3 | |||
Derivative Liabilities, Non-current [Member] | Forward Contracts [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (193) | (140) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 59 | 35 | |||
Derivative Financial Instruments, Assets [Member] | |||||
Derivative [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement | 1,523 | 1,367 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (1,221) | (975) | |||
Derivative Financial Instruments, Liabilities [Member] | |||||
Derivative [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement | (1,711) | (1,353) | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | $ 1,268 | $ 1,037 | |||
[1] | At December 31, 2018 and 2017, we had $244 million and $155 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, 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. | ||||
[3] | At December 31, 2017, current and long-term derivative assets are shown net of collateral of $(8) million and $(2) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $52 million and $20 million, respectively. | ||||
[4] | Includes OTC swaps and options. |
Derivative Instruments (Textual
Derivative Instruments (Textuals) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivatives, Fair Value [Line Items] | |||
Derivative, Collateral, Right to Reclaim Cash | $ 244 | $ 155 | |
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 | 7 years | ||
Derivative, Net Liability Position, Aggregate Fair Value | $ 229 | ||
Collateral Already Posted, Aggregate Fair Value | 178 | ||
Additional Collateral, Aggregate Fair Value | 3 | ||
Other Comprehensive Income Loss Derivatives Qualifying As Hedges Tax | 5 | 6 | $ 1 |
(Gain) Loss on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net | 1 | 0 | 3 |
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | (11) | ||
Collateral Offset in Current Derivatives Assets | (58) | (8) | |
Collateral Offset in Long-Term Derivative Assets | (8) | (2) | |
Collateral Offset in Current Derivative Liabilities | 49 | 52 | |
Collateral Offset in Long-term Derivative Liabilities | 64 | 20 | |
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 | (34) | (72) | (90) |
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) | $ (6) | $ (8) |
Use of Collateral (Details)
Use of Collateral (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | |
Financial Instruments Owned and Pledged as Collateral [Line Items] | |||
Margin Deposit Assets | [1] | $ 343 | $ 221 |
Natural gas and power prepayments | 31 | 23 | |
Total margin deposits and natural gas and power prepayments with our counterparties | [2] | 374 | 244 |
Letters of credit issued | 1,166 | 885 | |
First priority liens under power and natural gas agreements | 92 | 102 | |
First priority liens under interest rate hedging instruments | 10 | 31 | |
Letters of Credit Issued and First Priority Liens Under Power Natural Gas And Interest Rate Hedging Instruments | 1,268 | 1,018 | |
Margin deposits posted with us by our counterparties | [1],[3] | 52 | 4 |
Letters of credit posted with us by our counterparties | 27 | 30 | |
Total margin deposits and letters of credit posted with us by our counterparties | 79 | 34 | |
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 | 286 | 171 | |
Other Assets [Member] | |||
Financial Instruments Owned and Pledged as Collateral [Line Items] | |||
Total margin deposits and natural gas and power prepayments with our counterparties | 9 | 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 | 79 | 64 | |
Margin deposits posted with us by our counterparties | 32 | 2 | |
Other Current Liabilities [Member] | |||
Financial Instruments Owned and Pledged as Collateral [Line Items] | |||
Margin deposits posted with us by our counterparties | $ 20 | $ 2 | |
[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, 2018 and 2017, $79 million and $64 million, respectively, were included in current and long-term derivative assets and liabilities, $286 million and $171 million, respectively, were included in margin deposits and other prepaid expense and $9 million and $9 million, respectively, were included in other assets on our Consolidated Balance Sheets. | ||
[3] | At December 31, 2018 and 2017, $32 million and $2 million, respectively, were included in current and long-term derivative assets and liabilities and $20 million and $2 million, respectively, were included in other current liabilities on our Consolidated Balance Sheets. |
Income Taxes (Income Tax Expens
Income Taxes (Income Tax Expense (Benefit)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | $ 168 | $ 413 | $ 56 |
U.S. | 47 | (358) | 116 |
International | 27 | 27 | 24 |
Total | $ 74 | $ (331) | $ 140 |
Income Taxes (Components of Inc
Income Taxes (Components of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Federal | $ 0 | $ (10) | $ (10) |
State | 20 | 18 | 14 |
Foreign | (3) | (14) | 1 |
Total current | 17 | (6) | 5 |
Federal | (1) | 5 | 10 |
State | (6) | 6 | 27 |
Foreign | 54 | 3 | 6 |
Total deferred | 47 | 14 | 43 |
Total income tax expense (benefit) | $ 64 | $ 8 | $ 48 |
Income Taxes (Effective Income
Income Taxes (Effective Income Tax Expense (Benefit) Rate) (Details) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax [Line Items] | |||
Federal statutory tax expense (benefit) rate | 21.00% | 35.00% | 35.00% |
State tax expense (benefit), net of federal benefit | 17.00% | (6.00%) | 19.40% |
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | 0.00% | (168.80%) | 0.00% |
Effective Income Tax Rate Reconciliation Change in Deferred Tax Assets, Valuation Allowance Due to Tax Rate Change | 0.00% | 168.80% | 0.00% |
Valuation allowances | (31.70%) | (33.00%) | (25.00%) |
Effective Income Tax Rate Reconciliation Change in Deferred Tax Assets, Valuation Allowance Due to Foreign Taxes | (138.30%) | 0.50% | (0.10%) |
Effective Income Tax Rate Reconciliation, Decrease in foreign NOL Due to Change In Ownership | 202.30% | 0.00% | 0.00% |
Foreign taxes | 6.60% | (2.00%) | (0.60%) |
Change in unrecognized tax benefits | (8.00%) | 5.10% | (0.10%) |
Effective Income Tax Rate Reconciliation Nondeductible Expense Disallowed Compensation | 7.70% | (0.60%) | 0.90% |
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Percent | (1.50%) | (0.90%) | 2.20% |
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Other, Percent | 1.40% | (0.80%) | 2.00% |
Effective Tax Rate Reconciliation, Merger Related Fees/Expense | 12.70% | 0.00% | 0.00% |
Effective Income Tax Rate Reconciliation, Depletion In Excess Of Basis | (4.00%) | 0.00% | 0.00% |
Permanent differences and other items | 1.30% | 0.30% | 0.60% |
Effective income tax expense (benefit) rate | 86.50% | (2.40%) | 34.30% |
Income Taxes (Deferred Tax Asse
Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Valuation Allowance [Line Items] | |||
Income Tax Expense (Benefit), Intraperiod Tax Allocation | $ 1 | $ 6 | $ 0 |
NOL and credit carryforwards | 1,595 | 1,810 | |
Taxes related to risk management activities and derivatives | 7 | 20 | |
Reorganization items and impairments | 166 | 146 | |
Deferred Tax Assets, Other | 101 | 28 | |
Deferred tax assets before valuation allowance | 1,869 | 2,004 | |
Valuation allowance | (1,000) | (1,168) | |
Valuation Allowance, Deferred Tax Asset, Change in Amount | 168 | 413 | $ 56 |
Total deferred tax assets | 869 | 836 | |
Deferred tax liabilities: property, plant and equipment | (890) | (805) | |
Deferred Tax Liabilities, Gross | (890) | (805) | |
Deferred Tax Liabilities, Net | (21) | ||
Net deferred tax asset (liability) | 31 | ||
Deferred Tax Liabilities, Gross, Noncurrent | (22) | (28) | |
Deferred income tax asset, non-current | 1 | $ 59 | |
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Balance, beginning of period | $ (38) | $ (59) | $ (58) |
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions | 7 | 0 | 0 |
Decreases related to prior year tax positions | 17 | 11 | 1 |
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions | 0 | (2) | (2) |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 0 | 12 | 0 |
Balance, end of period | $ (28) | $ (38) | $ (59) |
Income Taxes (Textuals) (Detail
Income Taxes (Textuals) (Details) | 12 Months Ended | |||
Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Intraperiod income tax [Line Items] | ||||
Number of States for NOL Carryforwards | 26 | |||
Federal statutory tax expense (benefit) rate | 21.00% | 35.00% | 35.00% | |
Income Tax Disclosure (Textuals) [Abstract] | ||||
Unrecognized Tax Benefits | $ 28,000,000 | $ 38,000,000 | $ 59,000,000 | $ 58,000,000 |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 16,000,000 | |||
Unrecognized Tax Benefits Resulting in Net Operating Loss Carryforward | 12,000,000 | |||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | 2,000,000 | 4,000,000 | ||
Valuation allowance | 1,000,000,000 | 1,168,000,000 | ||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 168,000,000 | 413,000,000 | 56,000,000 | |
Deferred Tax Assets, Net of Valuation Allowance | 869,000,000 | 836,000,000 | ||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense | (2,000,000) | $ (8,000,000) | $ 0 | |
Expiration date 2024 through 2037 [Member] | ||||
Intraperiod income tax [Line Items] | ||||
Deferred Tax Assets, Operating Loss Carryforwards, Domestic | 6,400,000,000 | |||
Expiration date 2018 through 2037 [Member] | ||||
Income Tax Disclosure (Textuals) [Abstract] | ||||
Deferred Tax Assets, Operating Loss Carryforwards, State and Local | 3,300,000,000 | |||
Minimum [Member] | ||||
Income Tax Disclosure (Textuals) [Abstract] | ||||
Decrease in Unrecognized Tax Benefits is Reasonably Possible | 0 | |||
Maximum [Member] | ||||
Income Tax Disclosure (Textuals) [Abstract] | ||||
Decrease in Unrecognized Tax Benefits is Reasonably Possible | 1,000,000 | |||
Change in Valuation due to Merger [Member] | ||||
Income Tax Disclosure (Textuals) [Abstract] | ||||
Valuation Allowance, Deferred Tax Asset, Change in Amount | $ (58,000,000) |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | 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 | $ 79,000,000 | $ 0 | $ 0 | |
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost | 35,000,000 | |||
Stock-based compensation expense | 41,000,000 | 36,000,000 | 30,000,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value | 11,000,000 | 0 | 1,000,000 | |
Option exercises | 0 | 0 | 1,000,000 | |
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 | 88,000,000 | 23,000,000 | 17,000,000 | |
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 | 25,000,000 | |||
Share-based Compensation Arrangement by Liability Classified Share-based Payment Awards Accelerated Compensation Cost | 16,000,000 | |||
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards | $ 16,000,000 | $ 6,000,000 | $ 1,000,000 |
Defined Contribution and Defi_2
Defined Contribution and Defined Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Contribution and Defined Benefit Plans [Abstract] | |||
Defined Contribution Plan, Cost | $ 20 | $ 14 | $ 11 |
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 | 3.00% | ||
Assets for Plan Benefits, Defined Benefit Plan | $ 19 | 21 | |
Liability, Defined Benefit Plan | 27 | 29 | |
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position | 8 | 8 | |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) | 1 | 1 | $ 2 |
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | 4 | 5 | |
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year | 1 | $ 2 | |
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year | 4 | ||
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | $ 1 |
Capital Structure (Details)
Capital Structure (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Mar. 08, 2018 | Dec. 31, 2015 | |
Class of Stock [Line Items] | |||||
Sale of Stock, Price Per Share | $ 15.25 | ||||
Sale of Stock, Consideration Received on Transaction | $ 5,600 | ||||
Common Stock, authorized shares (in shares) | 5,000 | 1,400,000,000 | |||
Common Stock, issued shares (in shares) | 105.2 | 361,677,891 | |||
Common Stock, par value (in dollars per share) | $ 0.001 | $ 0.001 | |||
Common Stock, outstanding shares (in shares) | 105.2 | 360,516,091 | 359,061,764 | ||
Shares issued under Calpine Equity Incentive Plans | (121,906) | ||||
Stock Canceled During the Period, Shares | (360,394,185) | ||||
Stock Issued During Period, Shares, New Issues | 105.2 | ||||
Treasury Stock, Shares (in shares) | 0 | 1,161,800 | |||
Treasury Stock, Value | $ 0 | $ 15 | |||
Shares Issued [Member] | |||||
Class of Stock [Line Items] | |||||
Common Stock, issued shares (in shares) | 105.2 | 361,677,891 | 359,627,113 | 356,755,747 | |
Shares issued under Calpine Equity Incentive Plans | 355,805 | 2,050,778 | 2,871,366 | ||
Stock Canceled During the Period, Shares | (362,033,696) | ||||
Stock Issued During Period, Shares, New Issues | 105.2 | ||||
Share repurchase program | 0 | ||||
Treasury Stock [Member] | |||||
Class of Stock [Line Items] | |||||
Shares issued under Calpine Equity Incentive Plans | (477,711) | (596,451) | (449,079) | ||
Stock Canceled During the Period, Shares | 1,639,511 | ||||
Stock Issued During Period, Shares, New Issues | 0 | ||||
Share repurchase program | (22,527) | ||||
Treasury Stock, Shares (in shares) | 0 | 1,161,800 | 565,349 | 93,743 |
Commitments and Contingencies_2
Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Other Commitments [Line Items] | |||
Royalty Expense | $ 26 | $ 25 | $ 22 |
Guarantor Obligations, Current Carrying Value | 0 | ||
LTSA [Member] | |||
Unrecorded Unconditional Purchase Obligation | |||
Unrecorded Unconditional Purchase Obligation | 243 | ||
Electric Generation Equipment [Member] | |||
Other Commitments [Line Items] | |||
Operating Leases, Rent Expense, Net | 43 | 41 | 38 |
Office Equipment [Member] | |||
Other Commitments [Line Items] | |||
Operating Leases, Rent Expense, Net | 10 | $ 9 | $ 9 |
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 6 | ||
Unrecorded Unconditional Purchase Obligation | |||
Operating Leases, Future Minimum Payments, Due in Two Years | 6 | ||
Operating Leases, Future Minimum Payments, Due in Three Years | 8 | ||
Operating Leases, Future Minimum Payments, Due in Four Years | 8 | ||
Operating Leases, Future Minimum Payments, Due in Five Years | 7 | ||
Operating Leases, Future Minimum Payments, Due Thereafter | 18 | ||
Operating Leases, Future Minimum Payments Due | 53 | ||
Minimum [Member] | LTSA [Member] | |||
Unrecorded Unconditional Purchase Obligation | |||
Unrecorded Unconditional Purchase Obligation | $ 18 | ||
Unrecorded Unconditional Purchase Obligation, Term | 1 year | ||
Maximum [Member] | LTSA [Member] | |||
Unrecorded Unconditional Purchase Obligation | |||
Unrecorded Unconditional Purchase Obligation, Term | 19 years |
Commitments and Contingencies_3
Commitments and Contingencies (Schedules of Future Minimum Rental Payments) (Details) $ in Millions | Dec. 31, 2018USD ($) |
Land and Other Operating Leases [Member] | |
Operating Leased Assets [Line Items] | |
Operating Leases, Future Minimum Payments Due, Next Twelve Months | $ 13 |
Operating Leases, Future Minimum Payments, Due in Two Years | 13 |
Operating Leases, Future Minimum Payments, Due in Three Years | 12 |
Operating Leases, Future Minimum Payments, Due in Four Years | 10 |
Operating Leases, Future Minimum Payments, Due in Five Years | 10 |
Operating Leases, Future Minimum Payments, Due Thereafter | 174 |
Operating Leases, Future Minimum Payments Due | 232 |
KIAC [Member] | |
Operating Leased Assets [Line Items] | |
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 31 |
Operating Leases, Future Minimum Payments, Due in Two Years | 0 |
Operating Leases, Future Minimum Payments, Due in Three Years | 0 |
Operating Leases, Future Minimum Payments, Due in Four Years | 0 |
Operating Leases, Future Minimum Payments, Due in Five Years | 0 |
Operating Leases, Future Minimum Payments, Due Thereafter | 0 |
Operating Leases, Future Minimum Payments Due | 31 |
Operting Lease Assets Total [Member] | |
Operating Leased Assets [Line Items] | |
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 44 |
Operating Leases, Future Minimum Payments, Due in Two Years | 13 |
Operating Leases, Future Minimum Payments, Due in Three Years | 12 |
Operating Leases, Future Minimum Payments, Due in Four Years | 10 |
Operating Leases, Future Minimum Payments, Due in Five Years | 10 |
Operating Leases, Future Minimum Payments, Due Thereafter | 174 |
Operating Leases, Future Minimum Payments Due | 263 |
Natural Gas [Member] | |
Operating Leased Assets [Line Items] | |
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 415 |
Operating Leases, Future Minimum Payments, Due in Two Years | 172 |
Operating Leases, Future Minimum Payments, Due in Three Years | 134 |
Operating Leases, Future Minimum Payments, Due in Four Years | 101 |
Operating Leases, Future Minimum Payments, Due in Five Years | 93 |
Operating Leases, Future Minimum Payments, Due Thereafter | 201 |
Operating Leases, Future Minimum Payments Due | $ 1,116 |
Commitments and Contingencies_4
Commitments and Contingencies (Schedule of Guarantor Obligations) (Details) $ in Millions | Dec. 31, 2018USD ($) | |
Loans Payable [Member] | ||
Guarantor Obligations [Line Items] | ||
Guarantee Obligations Balance On First Anniversary | $ 30 | [1] |
Guarantee Obligations Balance On Second Anniversary | 30 | [1] |
Guarantee Obligations Balance On Third Anniversary | 29 | [1] |
Guarantee Obligations Balance On Fourth Anniversary | 24 | [1] |
Guarantee Obligations Balance On Fifth Anniversary | 14 | [1] |
Guarantee Obligations Due After Five Years | 52 | [1] |
Guarantor Obligations, Maximum Exposure, Undiscounted | 179 | [1] |
Financial Standby Letter of Credit [Member] | ||
Guarantor Obligations [Line Items] | ||
Guarantee Obligations Balance On First Anniversary | 1,321 | [2],[3],[4] |
Guarantee Obligations Balance On Second Anniversary | 6 | [2],[3],[4] |
Guarantee Obligations Balance On Third Anniversary | 0 | [2],[3],[4] |
Guarantee Obligations Balance On Fourth Anniversary | 0 | [2],[3],[4] |
Guarantee Obligations Balance On Fifth Anniversary | 38 | [2],[3],[4] |
Guarantee Obligations Due After Five Years | 0 | [2],[3],[4] |
Guarantor Obligations, Maximum Exposure, Undiscounted | 1,365 | [2],[3],[4] |
Surety Bonds [Member] | ||
Guarantor Obligations [Line Items] | ||
Guarantee Obligations Balance On First Anniversary | 12 | [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 | 76 | [4],[5],[6] |
Guarantor Obligations, Maximum Exposure, Undiscounted | 95 | [4],[5],[6] |
Accounts Receivable Sales Program [Member] | ||
Guarantor Obligations [Line Items] | ||
Guarantee Obligations Balance On First Anniversary | 238 | [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 | 238 | [7] |
Gurantee Obligations Total [Member] | ||
Guarantor Obligations [Line Items] | ||
Guarantee Obligations Balance On First Anniversary | 1,601 | |
Guarantee Obligations Balance On Second Anniversary | 43 | |
Guarantee Obligations Balance On Third Anniversary | 29 | |
Guarantee Obligations Balance On Fourth Anniversary | 24 | |
Guarantee Obligations Balance On Fifth Anniversary | 52 | |
Guarantee Obligations Due After Five Years | 128 | |
Guarantor Obligations, Maximum Exposure, Undiscounted | $ 1,877 | |
[1] | Represents Calpine Corporation guarantees of certain power plant capital leases and related interest. All guaranteed capital 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, 2018, 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 29, 2019. |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
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 | $ 238 | $ 196 | |
Notes Receivable, Related Parties, Current | 34 | 26 | |
Trade Receivables Sold | 2,400 | 2,200 | $ 165 |
Cash Flows Between Transferor and Transferee, Proceeds from New Transfers | 2,300 | $ 2,200 | $ 165 |
Revenue from Related Parties | 76 | ||
Related Party Transaction, Purchases from Related Party | $ 12 |
Segment and Significant Custo_3
Segment and Significant Customer Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | $ 2,354 | $ 2,890 | $ 2,259 | $ 2,009 | $ 1,801 | $ 2,586 | $ 2,084 | $ 2,281 | $ 9,512 | [1] | $ 8,752 | [1] | $ 6,716 | [1] | |
Commodity Margin | 3,033 | 2,708 | 2,604 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | [2] | (270) | (294) | (75) | |||||||||||
Operating and maintenance expense | 1,020 | 1,080 | 977 | ||||||||||||
Depreciation and amortization expense | 739 | 724 | 662 | ||||||||||||
General and other administrative expense | 158 | 155 | 140 | ||||||||||||
Other Cost and Expense, Operating | 98 | 85 | 79 | ||||||||||||
Impairment losses | 10 | 41 | 13 | ||||||||||||
(Gain) on sale of assets, net | 0 | (27) | (157) | ||||||||||||
(Income) from unconsolidated subsidiaries | 24 | 22 | 24 | ||||||||||||
Income from operations | $ 105 | $ 568 | $ 417 | $ (328) | $ (100) | $ 393 | $ 13 | $ 72 | 762 | 378 | 839 | ||||
Interest expense, net of interest income | 617 | 621 | 631 | ||||||||||||
Debt Extinguishment Costs and Other (Income) Expense, Net | 53 | 70 | 49 | ||||||||||||
Income before income taxes | 92 | (313) | 159 | ||||||||||||
Lease levelization | 0 | (8) | (2) | ||||||||||||
Contract amortization | $ 100 | $ 175 | $ 218 | ||||||||||||
Number of significant customers | 0 | 0 | 0 | ||||||||||||
West [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | [1] | $ 1,988 | $ 1,881 | $ 1,545 | |||||||||||
Commodity Margin | 1,060 | 970 | 984 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | [2] | (165) | (19) | (11) | |||||||||||
Operating and maintenance expense | 348 | 361 | 355 | ||||||||||||
Depreciation and amortization expense | 269 | 240 | 224 | ||||||||||||
General and other administrative expense | 40 | 45 | 38 | ||||||||||||
Other Cost and Expense, Operating | 42 | 38 | 33 | ||||||||||||
Impairment losses | 0 | 28 | 13 | ||||||||||||
(Gain) on sale of assets, net | 0 | 0 | |||||||||||||
(Income) from unconsolidated subsidiaries | 0 | 0 | 0 | ||||||||||||
Income from operations | 196 | 239 | 310 | ||||||||||||
Texas [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | [1] | 2,860 | 2,342 | 2,145 | |||||||||||
Commodity Margin | 646 | 552 | 543 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | [2] | (197) | (174) | 12 | |||||||||||
Operating and maintenance expense | 272 | 308 | 298 | ||||||||||||
Depreciation and amortization expense | 237 | 208 | 205 | ||||||||||||
General and other administrative expense | 61 | 66 | 56 | ||||||||||||
Other Cost and Expense, Operating | 24 | 14 | 8 | ||||||||||||
Impairment losses | 0 | 13 | 0 | ||||||||||||
(Gain) on sale of assets, net | 0 | 0 | |||||||||||||
(Income) from unconsolidated subsidiaries | 0 | 0 | 0 | ||||||||||||
Income from operations | (145) | (231) | (12) | ||||||||||||
East [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | [1] | 1,987 | 1,658 | 1,657 | |||||||||||
Commodity Margin | 970 | 790 | 905 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | [2] | 40 | (62) | 15 | |||||||||||
Operating and maintenance expense | 269 | 302 | 312 | ||||||||||||
Depreciation and amortization expense | 180 | 201 | 214 | ||||||||||||
General and other administrative expense | 38 | 27 | 40 | ||||||||||||
Other Cost and Expense, Operating | 32 | 33 | 38 | ||||||||||||
Impairment losses | 10 | 0 | 0 | ||||||||||||
(Gain) on sale of assets, net | (27) | (157) | |||||||||||||
(Income) from unconsolidated subsidiaries | 26 | 24 | 24 | ||||||||||||
Income from operations | 507 | 216 | 497 | ||||||||||||
Consolidation, Eliminations [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | [1] | (1,299) | (926) | (151) | |||||||||||
Commodity Margin | 0 | 0 | 0 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | (32) | [2] | (29) | (29) | |||||||||||
Operating and maintenance expense | (32) | (29) | (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] | 3,976 | 3,797 | 1,520 | |||||||||||
Commodity Margin | 357 | 396 | 172 | ||||||||||||
Mark-to-Market Commodity Activity, Net and Other Revenue | 84 | [2] | (10) | (62) | |||||||||||
Operating and maintenance expense | 163 | 138 | 41 | ||||||||||||
Depreciation and amortization expense | 53 | 75 | 19 | ||||||||||||
General and other administrative expense | 19 | 17 | 6 | ||||||||||||
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) | 0 | ||||||||||||
Income from operations | 204 | 154 | 44 | ||||||||||||
Intersegment Eliminations [Member] | West [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | 488 | 324 | 20 | ||||||||||||
Intersegment Eliminations [Member] | Texas [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | 573 | 361 | 81 | ||||||||||||
Intersegment Eliminations [Member] | East [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | 234 | 237 | 48 | ||||||||||||
Intersegment Eliminations [Member] | Retail [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Operating revenues | 4 | 4 | 2 | ||||||||||||
Other Assets [Member] | |||||||||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||||||||||||||
Contract amortization | $ 104 | $ 178 | $ 122 | ||||||||||||
[1] | Includes intersegment revenues of $488 million, $324 million and $20 million in the West, $573 million, $361 million and $81 million in Texas, $234 million, $237 million and $48 million in the East and $4 million, $4 million, $2 million in Retail for the years ended December 31, 2018, 2017 and 2016, respectively. | ||||||||||||||
[2] | Includes nil, $(8) million and $(2) million of lease levelization and $104 million, $178 million and $122 million of amortization expense for the years ended December 31, 2018, 2017 and 2016, respectively. |
Quarterly Consolidated Financ_3
Quarterly Consolidated Financial Data (unaudited) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||
Operating revenues | $ 2,354 | $ 2,890 | $ 2,259 | $ 2,009 | $ 1,801 | $ 2,586 | $ 2,084 | $ 2,281 | $ 9,512 | [1] | $ 8,752 | [1] | $ 6,716 | [1] |
Income (loss) from operations | 105 | 568 | 417 | (328) | (100) | 393 | 13 | 72 | 762 | 378 | 839 | |||
Net income (loss) attributable to Calpine | $ (16) | $ 272 | $ 352 | $ (598) | $ (292) | $ 225 | $ (216) | $ (56) | $ 10 | $ (339) | $ 92 | |||
[1] | Includes intersegment revenues of $488 million, $324 million and $20 million in the West, $573 million, $361 million and $81 million in Texas, $234 million, $237 million and $48 million in the East and $4 million, $4 million, $2 million in Retail for the years ended December 31, 2018, 2017 and 2016, respectively. |
Schedule of Valuation and Qua_2
Schedule of Valuation and Qualifying Accounts Disclosure (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
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 | $ 6 | $ 2 | |
Charged to Expense | 5 | 4 | 4 | |
Charged to Other Accounts | 1 | 2 | 0 | |
Deductions | [1] | (6) | 3 | 0 |
Balance at End of Year | 9 | 9 | 6 | |
Deferred Tax Asset Valuation Allowance [Member] | ||||
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | ||||
Balance at Beginning of Year | 1,168 | 1,581 | 1,637 | |
Charged to Expense | (168) | (413) | (56) | |
Charged to Other Accounts | 0 | 0 | 0 | |
Deductions | [1] | 0 | 0 | 0 |
Balance at End of Year | $ 1,000 | $ 1,168 | $ 1,581 | |
[1] | Represents write-offs of accounts considered to be uncollectible and previously reserved. |