Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2019 | Jul. 31, 2019 | |
Cover page. | ||
City Area Code | 207 | |
Local Phone Number | 629-1200 | |
Entity Current Reporting Status | Yes | |
Security Exchange Name | NYSE | |
Title of 12(b) Security | Common Stock, par value $0.01 per share | |
Entity Incorporation, State or Country Code | NY | |
Document Transition Report | false | |
Document Quarterly Report | true | |
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2019 | |
Entity File Number | 001-37660 | |
Document Fiscal Year Focus | 2019 | |
Document Fiscal Period Focus | Q2 | |
Trading Symbol | AGR | |
Entity Registrant Name | Avangrid, Inc. | |
Entity Central Index Key | 0001634997 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Emerging Growth Company | false | |
Entity Small Business | false | |
Entity Common Stock, Shares Outstanding (in shares) | 309,005,272 | |
Entity Tax Identification Number | 14-1798693 | |
Entity Address, Address Line One | 180 Marsh Hill Road | |
Entity Address, Postal Zip Code | 06477 | |
Entity Interactive Data Current | Yes | |
Entity Shell Company | false | |
Entity Address, City or Town | Orange, | |
Entity Address, State or Province | CT |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Income Statement [Abstract] | ||||
Operating Revenues | $ 1,400 | $ 1,402 | $ 3,242 | $ 3,267 |
Operating Expenses | ||||
Purchased power, natural gas and fuel used | 259 | 279 | 822 | 855 |
Loss from assets held for sale | 0 | 10 | 0 | 15 |
Operations and maintenance | 573 | 533 | 1,126 | 1,060 |
Depreciation and amortization | 222 | 215 | 444 | 418 |
Taxes other than income taxes | 139 | 143 | 302 | 294 |
Total Operating Expenses | 1,193 | 1,180 | 2,694 | 2,642 |
Operating Income | 207 | 222 | 548 | 625 |
Other Income and (Expense) | ||||
Other income (expense) | 2 | (20) | (5) | (41) |
Earnings from equity method investments | 1 | 5 | 2 | 7 |
Interest expense, net of capitalization | (76) | (70) | (154) | (144) |
Income Before Income Tax | 134 | 137 | 391 | 447 |
Income tax expense | 29 | 27 | 70 | 99 |
Net Income | 105 | 110 | 321 | 348 |
Less: Net (loss) income attributable to noncontrolling interests | (5) | 3 | (6) | (3) |
Net Income Attributable to Avangrid, Inc. | $ 110 | $ 107 | $ 327 | $ 351 |
Earnings Per Common Share, Basic (in usd per share) | $ 0.36 | $ 0.35 | $ 1.06 | $ 1.13 |
Earnings Per Common Share, Diluted (in usd per share) | $ 0.36 | $ 0.34 | $ 1.06 | $ 1.13 |
Weighted-average Number of Common Shares Outstanding: | ||||
Basic (in shares) | 309,491,082 | 309,517,854 | 309,491,082 | 309,515,758 |
Diluted (in shares) | 309,512,752 | 309,719,584 | 309,509,620 | 309,711,682 |
Condensed Consolidated Statem_2
Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Statement of Comprehensive Income [Abstract] | ||||
Net Income | $ 105 | $ 110 | $ 321 | $ 348 |
Other Comprehensive Income (Loss) | ||||
Gain on defined benefit plans, net of income taxes of $0.2 for both the three and six months ended | 0 | 1 | 0 | 1 |
Loss on nonqualified pension plans | (1) | 0 | (1) | 0 |
Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, net of income tax of $0.5 and $(1.5) for the three months ended, respectively, and $(10.4) and $(1.5) for the six months ended, respectively | 2 | (5) | (27) | (5) |
Reclassification to net income of loss (gain) on cash flow hedges, net of income taxes of $0.2 for the three months ended and $0.9 and $(7.2) for the six months ended, respectively | 1 | 0 | 3 | (10) |
Other Comprehensive Income (Loss) | 2 | (4) | (25) | (14) |
Comprehensive Income | 107 | 106 | 296 | 334 |
Less: Net (loss) income attributable to noncontrolling interests | (5) | 3 | (6) | (3) |
Comprehensive Income Attributable to Avangrid, Inc. | $ 112 | $ 103 | $ 302 | $ 337 |
Condensed Consolidated Statem_3
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Statement of Comprehensive Income [Abstract] | ||||
Gain (loss) on defined benefit and pension plans, income tax expense (benefit) | $ 0 | $ (0.2) | $ 0 | $ (0.2) |
Unrealized loss during period on derivatives qualified as cash flow hedges, income tax expense | 0.5 | (1.5) | (10.4) | (1.5) |
Reclassification to net income of (gains) losses on cash flow hedges, income tax expense | $ 0.2 | $ 0 | $ 0.9 | $ (7.2) |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Current Assets | ||
Cash and cash equivalents | $ 166 | $ 36 |
Accounts receivable and unbilled revenues, net | 1,009 | 1,142 |
Accounts receivable from affiliates | 13 | 6 |
Derivative assets | 12 | 16 |
Fuel and gas in storage | 91 | 109 |
Materials and supplies | 128 | 126 |
Prepayments and other current assets | 137 | 229 |
Regulatory assets | 247 | 299 |
Total Current Assets | 1,803 | 1,963 |
Total Property, Plant and Equipment ($1,048 and $726 related to VIEs, respectively) | 24,373 | 23,459 |
Operating lease right-of-use assets | 77 | 0 |
Equity method investments | 505 | 366 |
Other investments | 58 | 58 |
Regulatory assets | 2,554 | 2,640 |
Deferred income taxes regulatory | 0 | 6 |
Other Assets | ||
Goodwill | 3,127 | 3,127 |
Intangible assets | 318 | 323 |
Derivative assets | 79 | 63 |
Other | 247 | 162 |
Total Other Assets | 3,771 | 3,675 |
Total Assets | 33,141 | 32,167 |
Current Liabilities | ||
Current portion of debt | 374 | 394 |
Notes payable | 533 | 587 |
Interest accrued | 70 | 62 |
Accounts payable and accrued liabilities | 1,012 | 1,132 |
Accounts payable to affiliates | 48 | 58 |
Dividends payable | 136 | 136 |
Taxes accrued | 56 | 59 |
Operating lease liabilities | 11 | 0 |
Derivative liabilities | 25 | 44 |
Other current liabilities | 291 | 327 |
Regulatory liabilities | 256 | 205 |
Total Current Liabilities | 2,812 | 3,004 |
Regulatory liabilities | 3,286 | 3,223 |
Other Non-current Liabilities | ||
Deferred income taxes | 1,535 | 1,530 |
Deferred income | 1,351 | 1,385 |
Pension and other postretirement | 1,092 | 1,102 |
Operating lease liabilities | 69 | 0 |
Derivative liabilities | 122 | 97 |
Asset retirement obligations | 183 | 217 |
Environmental remediation costs | 333 | 339 |
Other | 527 | 499 |
Total Other Non-current Liabilities | 5,212 | 5,169 |
Non-current debt | 6,282 | 5,368 |
Total Non-current Liabilities | 14,780 | 13,760 |
Total Liabilities | 17,592 | 16,764 |
Commitments and Contingencies | ||
Stockholders’ Equity: | ||
Common stock, $.01 par value, 500,000,000 shares authorized, 309,752,140 shares issued; 309,005,272 shares outstanding, respectively | 3 | 3 |
Additional paid in capital | 13,659 | 13,657 |
Treasury stock | (12) | (12) |
Retained earnings | 1,594 | 1,528 |
Accumulated other comprehensive loss | (109) | (72) |
Total Stockholders’ Equity | 15,135 | 15,104 |
Non-controlling interests | 414 | 299 |
Total Equity | 15,549 | 15,403 |
Total Liabilities and Equity | $ 33,141 | $ 32,167 |
Condensed Consolidated Balanc_2
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Property, Plant and Equipment, VIEs | $ 24,373 | $ 23,459 |
Common stock, par value (in usd per share) | $ 0.01 | $ 0.01 |
Common stock, authorized (in shares) | 500,000,000 | 500,000,000 |
Common stock, issued (in shares) | 309,752,140 | 309,752,140 |
Common stock, outstanding (in shares) | 309,005,272 | 309,005,272 |
Variable Interest Entity, Primary Beneficiary | ||
Property, Plant and Equipment, VIEs | $ 1,048 | $ 726 |
Condensed Consolidated Statem_4
Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Cash Flow from Operating Activities: | ||
Net Income | $ 321 | $ 348 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 444 | 418 |
Loss from assets held for sale | 0 | 15 |
Regulatory assets/liabilities amortization and carrying cost | 32 | 37 |
Pension cost | 45 | 62 |
Earnings from equity method investments | (2) | (7) |
Distributions of earnings received from equity method investments | 2 | 7 |
Unrealized gain on marked-to-market derivative contracts | (23) | (4) |
Deferred taxes | (22) | 106 |
Other non-cash items | (14) | (11) |
Changes in operating assets and liabilities: | ||
Current assets | 295 | 120 |
Noncurrent assets | (34) | (69) |
Current liabilities | (247) | (122) |
Noncurrent liabilities | 20 | 83 |
Net Cash Provided by Operating Activities | 817 | 983 |
Cash Flow from Investing Activities: | ||
Capital expenditures | (1,337) | (751) |
Contributions in aid of construction | 21 | 23 |
Proceeds from sale of assets | 2 | 136 |
Distributions received from equity method investments | 5 | 2 |
Other investments and equity method investments, net | (143) | (16) |
Net Cash Used in Investing Activities | (1,452) | (606) |
Cash Flow from Financing Activities: | ||
Non-current note issuance | 1,188 | 325 |
Repayments of non-current debt | (194) | (65) |
Repayments of other short-term debt, net | (54) | (539) |
Repayments of financing leases | (25) | (12) |
Repurchase of common stock | 0 | (4) |
Issuance of common stock | 0 | (2) |
Distributions to noncontrolling interests | (10) | (22) |
Distributions to noncontrolling interests | 131 | 220 |
Dividends paid | (272) | (267) |
Net Cash Provided by (Used in) Financing Activities | 764 | (366) |
Net Increase in Cash, Cash Equivalents and Restricted Cash | 129 | 11 |
Cash, Cash Equivalents and Restricted Cash, Beginning of Period | 43 | 46 |
Cash, Cash Equivalents and Restricted Cash, End of Period | 172 | 57 |
Supplemental Cash Flow Information | ||
Cash paid for interest, net of amounts capitalized | 125 | 113 |
Cash paid/(refund) for income taxes | $ 3 | $ (13) |
Condensed Consolidated Statem_5
Condensed Consolidated Statements of Changes in Equity (unaudited) - USD ($) $ in Millions | Total | Total Stockholders’ Equity | Common Stock | Additional paid-in capital | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Loss | Non controlling Interests | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Adoption of accounting standards | $ (1) | |||||||||
Balance, beginning of period at Dec. 31, 2017 | $ 15,096 | $ 15,077 | $ 3 | $ 13,653 | $ (8) | $ 1,475 | (46) | $ 19 | ||
Balance, beginning of period (in shares) at Dec. 31, 2017 | [1] | 309,005,272 | ||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net income (loss) | 348 | 351 | 351 | (3) | ||||||
Other comprehensive income (loss), net of tax of $(1.3), $0.7, $(8.5), and $(9.5), respectively | (14) | (14) | (14) | |||||||
Comprehensive income | 334 | |||||||||
Dividends declared ($0.432, $0.44, $0.864, and $0.88 per share) per share, respectively) | (267) | (267) | (267) | |||||||
Release of common stock held in trust (in shares) | [1] | 0 | ||||||||
Issuance of common stock | 2 | 2 | (1) | 3 | ||||||
Issuances of common stock (in shares) | [1] | (81,208) | ||||||||
Repurchase of common stock | (4) | (4) | (4) | |||||||
Repurchase of common stock (in shares) | [1] | (81,208) | ||||||||
Stock-based compensation | 1 | 1 | 1 | |||||||
Distributions to noncontrolling interests | (41) | (41) | ||||||||
Contributions from noncontrolling interests | 215 | (3) | (3) | 218 | ||||||
Balance, end of period at Jun. 30, 2018 | 15,468 | 15,135 | $ 3 | 13,655 | (12) | 1,550 | (61) | 333 | ||
Balance, end of period (in shares) at Jun. 30, 2018 | [1] | 309,005,272 | ||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Adoption of accounting standards | 0 | |||||||||
Balance, beginning of period at Mar. 31, 2018 | 15,319 | 15,171 | $ 3 | 13,654 | (8) | 1,579 | (57) | 148 | ||
Balance, beginning of period (in shares) at Mar. 31, 2018 | [1] | 309,086,480 | ||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net income (loss) | 110 | 107 | 107 | 3 | ||||||
Other comprehensive income (loss), net of tax of $(1.3), $0.7, $(8.5), and $(9.5), respectively | (4) | (4) | (4) | |||||||
Comprehensive income | 106 | |||||||||
Dividends declared ($0.432, $0.44, $0.864, and $0.88 per share) per share, respectively) | $ (133) | (133) | (133) | |||||||
Release of common stock held in trust (in shares) | 0 | |||||||||
Issuances of common stock (in shares) | (81,208) | |||||||||
Repurchase of common stock | $ (4) | (4) | (4) | |||||||
Repurchase of common stock (in shares) | [1] | (81,208) | ||||||||
Stock-based compensation | 1 | 1 | 1 | |||||||
Distributions to noncontrolling interests | (30) | (30) | ||||||||
Contributions from noncontrolling interests | 209 | (3) | (3) | 212 | ||||||
Balance, end of period at Jun. 30, 2018 | 15,468 | 15,135 | $ 3 | 13,655 | (12) | 1,550 | (61) | 333 | ||
Balance, end of period (in shares) at Jun. 30, 2018 | [1] | 309,005,272 | ||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Adoption of accounting standards | (12) | |||||||||
Balance, beginning of period at Dec. 31, 2018 | $ 15,403 | 15,104 | $ 3 | 13,657 | (12) | 1,528 | (72) | 299 | ||
Balance, beginning of period (in shares) at Dec. 31, 2018 | 309,005,272 | 309,005,272 | [1] | |||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net income (loss) | $ 321 | 327 | 327 | (6) | ||||||
Other comprehensive income (loss), net of tax of $(1.3), $0.7, $(8.5), and $(9.5), respectively | (25) | (25) | (25) | |||||||
Comprehensive income | 296 | |||||||||
Dividends declared ($0.432, $0.44, $0.864, and $0.88 per share) per share, respectively) | $ (272) | (272) | (272) | |||||||
Release of common stock held in trust (in shares) | 0 | |||||||||
Stock-based compensation | $ 2 | 2 | 2 | |||||||
Distributions to noncontrolling interests | (10) | (10) | ||||||||
Contributions from noncontrolling interests | 131 | 131 | ||||||||
Balance, end of period at Jun. 30, 2019 | $ 15,549 | 15,135 | $ 3 | 13,659 | (12) | 1,594 | (109) | 414 | ||
Balance, end of period (in shares) at Jun. 30, 2019 | 309,005,272 | 309,005,272 | [1] | |||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Adoption of accounting standards | 0 | |||||||||
Balance, beginning of period at Mar. 31, 2019 | $ 15,456 | 15,158 | $ 3 | 13,658 | (12) | 1,620 | (111) | 298 | ||
Balance, beginning of period (in shares) at Mar. 31, 2019 | [1] | 309,005,272 | ||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net income (loss) | 105 | 110 | 110 | (5) | ||||||
Other comprehensive income (loss), net of tax of $(1.3), $0.7, $(8.5), and $(9.5), respectively | 2 | 2 | 2 | |||||||
Comprehensive income | 107 | |||||||||
Dividends declared ($0.432, $0.44, $0.864, and $0.88 per share) per share, respectively) | $ (136) | (136) | (136) | |||||||
Release of common stock held in trust (in shares) | 0 | |||||||||
Issuances of common stock (in shares) | 0 | |||||||||
Stock-based compensation | $ 1 | 1 | 1 | |||||||
Distributions to noncontrolling interests | (7) | (7) | ||||||||
Contributions from noncontrolling interests | 128 | 128 | ||||||||
Balance, end of period at Jun. 30, 2019 | $ 15,549 | $ 15,135 | $ 3 | $ 13,659 | $ (12) | $ 1,594 | $ (109) | $ 414 | ||
Balance, end of period (in shares) at Jun. 30, 2019 | 309,005,272 | 309,005,272 | [1] | |||||||
[1] | (*) Par value of share amounts is $0.01 |
Condensed Consolidated Statem_6
Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Dec. 31, 2018 | |
Statement of Stockholders' Equity [Abstract] | |||||
Common stock, par value (in usd per share) | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 |
Other comprehensive income (loss), taxes | $ 0.7 | $ (1.3) | $ (9.5) | $ (8.5) | |
Dividends declared (in usd per share) | $ 0.44 | $ 0.432 | $ 0.88 | $ 0.864 |
Background and Nature of Operat
Background and Nature of Operations | 6 Months Ended |
Jun. 30, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Background and Nature of Operations | Background and Nature of Operations Avangrid, Inc., formerly Iberdrola USA, Inc. (AVANGRID, we or the Company), is an energy services holding company engaged in the regulated energy transmission and distribution business through its principal subsidiary, Avangrid Networks, Inc. (Networks), and in the renewable energy generation business through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.5% of the outstanding common stock of AVANGRID. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. |
Basis of Presentation
Basis of Presentation | 6 Months Ended |
Jun. 30, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying notes should be read in conjunction with the notes to the consolidated financial statements of Avangrid, Inc. and subsidiaries as of December 31, 2018 and 2017 and for the three years ended December 31, 2018 included in AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018 . The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. Intercompany accounts and transactions have been eliminated in consolidation. The year-end balance sheet data was derived from audited financial statements. The unaudited condensed consolidated financial statements for the interim periods have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the interim condensed consolidated financial statements do not include all the information and note disclosures required by U.S. GAAP for complete financial statements. We believe the disclosures made are adequate to make the information presented not misleading. In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated balance sheets, condensed consolidated statements of income, comprehensive income, cash flows and changes in equity for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three and six months ended June 30, 2019 , are not necessarily indicative of the results for the entire fiscal year ending December 31, 2019 . |
Significant Accounting Policies
Significant Accounting Policies and New Accounting Pronouncements | 6 Months Ended |
Jun. 30, 2019 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies and New Accounting Pronouncements | Significant Accounting Policies and New Accounting Pronouncements As of June 30, 2019 , the new accounting pronouncements that we have adopted as of January 1, 2019 , and reflected in our condensed consolidated financial statements are described below. There have been no other material changes to the significant accounting policies described in our consolidated financial statements as of December 31, 2018 and 2017 , and for the three years ended December 31, 2018 , except for the leases accounting policy described below. Significant Accounting Policies Leases We determine if an arrangement is a lease at inception. We classify a lease as a finance lease if it meets any one of specified criteria that in essence transfers ownership of the underlying asset to us by the end of the lease term. If a lease does not meet any of those criteria, we classify it as an operating lease. On our condensed consolidated balance sheets, we include, for operating leases: "Operating lease right-of-use (ROU) assets" and "Operating lease liabilities (current and non-current)"; and for finance leases: finance lease ROU assets in "Other assets" and liabilities in "Other current liabilities" and "Other liabilities." ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize lease ROU assets and liabilities at commencement of an arrangement based on the present value of lease payments over the lease term. Most of our leases do not provide an implicit rate, so we use our incremental borrowing rate based on information available at the lease commencement date to determine the present value of future payments. A lease ROU asset also includes any lease payments made at or before commencement date, minus any lease incentives received, and includes initial direct costs incurred. We do not record leases with an initial term of 12 months or less on the balance sheet, for all classes of underlying assets, and we recognize lease expense for those leases on a straight-line basis over the lease term. We include variable lease payments that depend on an index or a rate in the ROU asset and lease liability measurement based on the index or rate at the commencement date, or upon a modification. We do not include variable lease payments that do not depend on an index or a rate in the ROU asset and lease liability measurement. A lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. We recognize lease (rent) expense for operating lease payments on a straight-line basis over the lease term, or for our regulated companies we recognize the amount eligible for recovery under their rate plans, such as actual amounts paid. We amortize finance lease ROU assets on a straight-line basis over the lease term and recognize interest expense based on the outstanding lease liability. We have lease agreements with lease and nonlease components, and account for lease components and associated nonlease components together as a single lease component, for all classes of underlying assets. Adoption of New Accounting Pronouncements (a) Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC) Topic 842, Leases , with subsequent amendments issued in 2018. The new leases guidance affects all companies and organizations that lease assets, and requires them to record on their balance sheet ROU assets and lease liabilities for the rights and obligations created by those leases. Under ASC 842, a lease is an arrangement that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The new guidance retains a distinction between finance leases and operating leases, while requiring companies to recognize both types of leases on their balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the criteria for distinguishing between capital leases and operating leases in legacy U.S. GAAP - ASC 840. Lessor accounting remains substantially the same as ASC 840, but with some targeted improvements to align lessor accounting with the lessee accounting model and with the revised revenue recognition guidance under ASC 606. The new standard and amendments require new qualitative and quantitative disclosures for both lessees and lessors. We adopted ASC 842 effective January 1, 2019, and elected the optional transition method under which we initially applied the standard on that date without adjusting amounts for prior periods, which we continue to present in accordance with ASC 840, including related disclosures. We recorded the cumulative effect of applying the new leases guidance as an adjustment to beginning retained earnings. In connection with our adoption, we: • did not elect the package of three practical expedients available under the transition provisions which would have allowed us to not reassess: (i) whether expired or existing contracts were or contained leases, (ii) the lease classification for expired or existing leases, and (iii) whether previously capitalized initial direct costs for existing leases would qualify for capitalization under ASC 842. • elected the land easement practical expedient and did not reassess land easements that did not meet the definition of a lease prior to adoption. • used hindsight for determining the lease term and assessing the likelihood that a lease purchase option will be exercised in applying the new leases guidance. • did not separate lease and associated non-lease components for transitioned leases, but instead are accounting for them together as a single lease component. In March 2019, the FASB issued additional amendments to ASC 842 for minor codification improvements, which we early applied effective January 1, 2019, with no material effect to our condensed consolidated results of operations, financial position and cash flows. The cumulative effects of the changes to our condensed consolidated balance sheet as of January 1, 2019, were as follows: Balance at December 31, 2018 Adjustments Due to ASC 842 Balance at January 1, 2019 (Millions) Assets Total Property, Plant and Equipment $ 23,459 $ (147 ) $ 23,312 Operating lease right-of-use assets — 82 82 Other assets 162 146 308 Liabilities Current portion of debt $ 394 $ (28 ) $ 366 Operating lease liabilities, current — 8 8 Other current liabilities 327 28 355 Operating lease liabilities, long-term — 74 74 Other non-current liabilities 499 61 560 Non-current debt 5,368 (61 ) 5,307 Equity Retained earnings $ 1,528 $ (1 ) $ 1,527 Our adoption did not change the classification of lease-related expenses in our condensed consolidated statements of income, and we do not expect significant changes to our pattern of expense recognition. Certain contracts previously classified as lessor leases, consisting mainly of Renewables’ power purchase agreements, no longer meet the definition of a lease under ASC 842. As such, these contracts are accounted for under other U.S. GAAP, but there were no changes to our pattern of revenue recognition. As a result, we expect our adoption will not materially affect our cash flows. In comparison to our operating leases obligations disclosed as of December 31, 2018, certain land easement contracts that previously met the definition of a lease do not meet the ASC 842 definition of a lease, and therefore we excluded them from the transition adjustment. Our accounting for finance (formerly capital) leases is substantially unchanged. Refer to Note 8 for further details. (b) Targeted improvements to accounting for hedging activities In August 2017, the FASB issued targeted amendments with the objective to better align hedge accounting with an entity’s risk management activities in the financial statements, and to simplify the application of hedge accounting. The amendments address concerns of financial statement preparers over difficulties with applying hedge accounting and limitations for hedging both nonfinancial and financial risks and concerns of financial statement users over how hedging activities are reported in financial statements. The amended presentation and disclosure guidance is required only prospectively. Changes to the hedge accounting guidance to address those concerns: 1) expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with an entity’s risk management activities; 2) eliminate the separate measurement and reporting of hedge ineffectiveness, to reduce the complexity of preparing and understanding hedge results; 3) enhance disclosures and change the presentation of hedge results to align the effects of the hedging instrument and the hedged item in order to enhance transparency, comparability and understandability of hedge results; and 4) simplify the way assessments of hedge effectiveness may be performed to reduce the cost and complexity of applying hedge accounting. The amendments ease the administrative burden of hedge documentation requirements and assessing hedge effectiveness going forward. We adopted the hedge accounting amendments on January 1, 2019, and had no cumulative-effect adjustment to retained earnings because there were no amounts of ineffectiveness recorded for any existing hedges as of that date. Concurrently with the above targeted improvements, we adopted the additional amendments the FASB issued in October 2018 that permit use of the Overnight Index Swap rate based on the Secured Overnight Financing Rate as a U.S. benchmark interest rate for hedge accounting purposes. Use of that rate is in addition to the already eligible benchmark interest rates, which are: interest rates on direct Treasury obligations of the U.S. government, the London Interbank Offered Rate swap rate, the OIS Rate based on the Fed Funds Effective Rate and the Securities Industry and Financial Markets Association Municipal Swap Rate. (c) Reclassification of certain tax effects from accumulated other comprehensive income In February 2018, the FASB issued amendments to address a financial reporting issue that arose as a consequence of the Tax Cuts and Jobs Act of 2017 (the Tax Act) that the U.S. federal government enacted on December 22, 2017. Under previous guidance, an entity was required to include the adjustment of deferred taxes for the effect of a change in tax laws or rates in income from continuing operations, thus the associated tax effects of items within AOCI (referred to as stranded tax effects) did not reflect the appropriate tax rate. The amendments allow a reclassification from AOCI to retained earnings to eliminate the stranded tax effects resulting from the Tax Act. The amendments only relate to the reclassification of the income tax effects of the Tax Act, and do not affect the underlying guidance that requires the effect of a change in tax laws or rates to be included in income from continuing operations. We adopted the amendments effective January 1, 2019, and elected to reclassify the stranded tax effects of the Tax Act from AOCI to retained earnings at the beginning of the period of adoption. As a result, we reclassified approximately $12 million from AOCI to retained earnings within our condensed consolidated statements of changes in equity. Accounting Pronouncements Issued But Not Yet Adopted The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2018, that we have evaluated or are evaluating to determine their effect on our consolidated financial statements. (a) Measurement of credit losses on financial instruments, amendments and updates The FASB issued an accounting standards update in June 2016 that requires more timely recording of credit losses on loans and other financial instruments. The amendments affect entities that hold financial assets and net investment in leases that are not accounted for at fair value through net income (loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, etc.). They require an entity to present a financial asset (or group of financial assets) that is measured at amortized cost basis at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset(s) to present the net carrying value at the amount expected to be collected on the financial asset. The income statement reflects the measurement of credit losses for newly recognized financial assets, as well as the expected increases or decreases of expected credit losses that have taken place during the period. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. An entity must use judgment in determining the relevant information and estimation methods appropriate in its circumstances. The FASB subsequently issued various updates to this new guidance to clarify transition and scope requirements, make narrow-scope codification improvements and corrections, and provide targeted transition relief. The new guidance, including the subsequent amendments, is effective for public entities that are SEC filers - and do not early adopt the new guidance - for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We will not early adopt the amendments. Entities are to apply the amendments on a modified retrospective basis for most instruments. Our implementation plan and steps currently under way for our adoption include: identifying and evaluating financial assets within scope; documenting related technical accounting issues, policy considerations and financial reporting implications; and identifying changes to processes and controls to ensure all aspects of the new guidance are effectively addressed. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows. |
Revenue
Revenue | 6 Months Ended |
Jun. 30, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | Revenue We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale. The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about reportable segments, refer to Note 14. Networks Segment Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts, with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas. Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. Maine state law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to Federal Energy Regulatory Commission (FERC) regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO), or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer. The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service. Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms, other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives or ARPs. Renewables Segment Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all of the unit’s output. Renewables also has unbundled sales of electric energy and capacity, RECs and natural gas, which are generally for periods of less than a year. The performance obligations in substantially all of both bundled and unbundled arrangements for electricity and natural gas are satisfied over time, for which we record revenue based on the amount invoiced to the customer for the actual energy delivered. The performance obligation for stand-alone RECs is satisfied at a point in time, for which we record revenue when the performance obligation is satisfied upon delivery of the REC. Renewables classifies certain contracts for the sale of electricity as derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of Topic 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other Topic 606 revenue, which we recognize based on the amount invoiced to the customer. Other Other, which does not represent a segment, derives its revenues primarily from providing natural gas storage services to customers, gas trading operations generally classified as derivative revenue in accordance with the applicable accounting standards, gas trading contracts not classified as derivatives and other miscellaneous revenues including intersegment eliminations. Contract Costs and Contract Liabilities We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid for during the solar asset development period in 2018, and will amortize ratably into expense over the 15 -year life of the power purchase agreement (PPA), expected to commence in December 2021 upon commercial operation. We also have a contract asset for costs incurred to cancel a PPA, which we will amortize over the 10 -year contract period of the replacement PPA that will commence upon completion of the project. Contract assets totaled $12 million and $9 million at June 30, 2019 and December 31, 2018 , respectively, and are presented in "Other non-current assets" on our condensed consolidated balance sheets. We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period, and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years . TCC contract liabilities totaled $12 million and $9 million at June 30, 2019 and December 31, 2018 , respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $4 million and $9 million as revenue during the three and six months ended June 30, 2019 , respectively, and $4 million and $8 million for the three and six months ended June 30, 2018 , respectively. Revenues disaggregated by major source for our reportable segments for the three and six months ended June 30, 2019 and 2018 are as follows: Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 802 $ — $ — $ 802 $ 1,715 $ — $ — $ 1,715 Regulated operations – natural gas 249 — — 249 874 — — 874 Nonregulated operations – wind — 221 — 221 — 403 — 403 Nonregulated operations – solar — 8 — 8 — 13 — 13 Nonregulated operations – thermal — — — — — 16 — 16 Other(a) 18 24 — 42 55 17 (4 ) 68 Revenue from contracts with customers 1,069 253 — 1,322 2,644 449 (4 ) 3,089 Leasing revenue 3 — — 3 4 — — 4 Derivative revenue — 48 — 48 — 89 — 89 Alternative revenue programs 19 — — 19 35 — — 35 Other revenue 2 6 — 8 14 11 — 25 Total operating revenues $ 1,093 $ 307 $ — $ 1,400 $ 2,697 $ 549 $ (4 ) $ 3,242 Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 800 $ — $ — $ 800 $ 1,726 $ — $ — $ 1,726 Regulated operations – natural gas 266 — — 266 838 — — 838 Nonregulated operations – wind — 180 — 180 — 348 — 348 Nonregulated operations – solar — 6 — 6 — 8 — 8 Nonregulated operations – thermal — 1 — 1 — 14 — 14 Nonregulated operations – gas storage — — 6 6 — — 10 10 Other(a) 6 (10 ) (6 ) (10 ) 31 (33 ) 9 7 Revenue from contracts with customers 1,072 177 — 1,249 2,595 337 19 2,951 Leasing revenue 9 98 — 107 18 179 — 197 Derivative revenue — 22 — 22 — 65 10 75 Alternative revenue programs 25 — — 25 44 — — 44 Other revenue (1 ) — — (1 ) — — — — Total operating revenues $ 1,105 $ 297 $ — $ 1,402 $ 2,657 $ 581 $ 29 $ 3,267 (a) Primarily includes certain intra-month trading activities, billing, collection, and administrative charges, sundry billings, and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate, Gas and intersegment eliminations. Refer to Note 3 for details on the adoption of ASC 842 including a discussion regarding the classification of lease revenues. As of June 30, 2019 and December 31, 2018 , accounts receivable balances related to contracts with customers were approximately $980 million and $1,118 million , respectively, including unbilled revenues of $284 million and $374 million , which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets. As of June 30, 2019 , the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of June 30, 2019 2020 2021 2022 2023 2024 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ 1 $ 1 $ 1 $ 1 $ — $ 5 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 15 13 9 3 1 — 41 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 18 13 8 5 4 9 57 Total operating revenues $ 34 $ 27 $ 18 $ 9 $ 6 $ 9 $ 103 As of June 30, 2019 , the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2019 was $29 million . |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 6 Months Ended |
Jun. 30, 2019 | |
Regulated Operations [Abstract] | |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in the rate base or accruing carrying costs are the regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. The total net amount of these items is approximately $1,762 million . On August 25, 2014, the Maine Public Utility Commission (MPUC) approved a stipulation agreement that provided for a distribution rate increase for Central Maine Power (CMP) of approximately $24.3 million , effective July 1, 2014, with an allowed return on equity (ROE) of 9.45% and an allowed equity ratio of 50% . The stipulation provided for the implementation of a revenue decoupling mechanism (RDM), reserve accounting and sharing of incremental storm costs, a separate proceeding for recovery of a new billing system and no earning sharing. On May 29, 2018, a ten-person complaint was filed with the MPUC against CMP, Networks and AVANGRID. The complaint requested that the MPUC open a rate case to determine if CMP is making excessive returns on investment and, therefore, whether CMP’s retail rates should be lower. The complaint also requested the MPUC deny certain costs associated with the October 2017 windstorm. On July 24, 2018, the MPUC issued an order dismissing the complaint and its associated request to deny the recovery of costs associated with the October 2017 windstorm. The order initiated an investigation into CMP’s rates and revenue requirement and directed CMP to make a filing consistent with the requirements for a general rate case no later than October 15, 2018. Consistent with the order in the ten-person complaint proceeding, on August 7, 2018, the MPUC issued a Notice of Investigation, opening the proceeding in which CMP would make its rate case filing and through which the MPUC will examine the rates and revenue requirements of CMP. On October 15, 2018, CMP filed a general rate case as directed by the MPUC requesting a ROE of 10% and an equity ratio of 55% . CMP is proposing to use savings arising out of changes in federal taxation pursuant to the Tax Act to minimize its requested distribution rate increase while making its electric system more reliable. The MPUC initially established an 11-month process to review CMP’s filing, which extends through October of 2019. The Maine Public Advocate for utility issues filed a motion to delay CMP's rate order decision to allow incorporation of the results of the separate metering and billing investigation. CMP did not oppose this motion. We expect the MPUC to rule on the motion in August. CMP’s general rate case filing includes a proposal to enhance the resiliency of the energy grid by expanding vegetation management and pursuing additional reliability measures such as pole replacements and addition of tree wire in selected areas. Such investments are designed to strengthen CMP’s power grid so it can better stand up to severe weather. CMP is planning to use savings from the federal Tax Act to pay for the costs of resiliency programs, other investments in infrastructure and certain cost increases since 2014. On December 20, 2018, the MPUC released the findings of the forensic audit of CMP’s customer billing system and customer communication practices. On January 14, 2019, the MPUC issued an Order and Notice of Investigation initiating an investigation of CMP’s metering and billing practices and initiating a separate investigation of the audit of CMP’s customer service and communication practices and incorporating such investigation into the general rate case. On February 22, 2019, the MPUC issued the MPUC staff Bench Analysis (BA) on all revenue requirement issues in this case, including customer service issues. The BA includes, among other things, a proposal to reduce CMP’s existing distribution rates by $2.0 - $3.6 million , inclusive of one-time items from July 2018, and implement a management efficiency adjustment as part of the rate setting process to reduce the MPUC staff recommended "unadjusted" ROE of 9.35% by 75 to 100 basis points. On April 12, 2019, CMP filed rebuttal testimony to the Bench Analysis and intervenor testimony. On June 17, 2019, the MPUC Staff issued its Reply Bench Analysis in response to CMP’s rebuttal testimony, which includes a reduction of the "unadjusted" ROE recommendation to 8.75% based on current market conditions, maintains the proposed management efficiency adjustment of 75 to 100 basis points and proposes to maintain the current cap of $31.4 million on the shared service costs provided to CMP until a management audit on the cost effectiveness of such services is completed. We cannot predict the outcome of this matter. On June 15, 2016, the New York State Public Service Commission (NYPSC) approved the Joint Proposal filed with the NYPSC by New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RG&E) and by certain other signatory parties on February 19, 2016, in connection with a three -year rate plan for electric and gas service at NYSEG and RG&E effective May 1, 2016. Following the approval of the Joint Proposal, most of the regulatory deferrals related to NYSEG are amortized over a five -year period, except the portion of storm costs to be recovered over 10 years , unfunded deferred taxes being amortized over a period of 50 years and plant-related tax items which are amortized over the life of associated plant. Annual amortization expense for NYSEG is approximately $16.5 million per rate year. RG&E items that are being amortized are plant- related tax items, which are amortized over the life of associated plant, and unfunded deferred taxes being amortized over a period of 50 years . A majority of the other items related to RG&E, which net to a regulatory liability, remain deferred and will not be amortized until future proceedings. The approved Joint Proposal provides for annual rate increases and allowed rates of return on common equity of 9.0% for NYSEG and RG&E. The equity ratio for each company is 48% ; however, the equity ratio is set at the actual up to 50% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increases as the ROE increases, with customers receiving 50% , 75% and 90% of earnings over 9.5% , 10.0% and 10.5% ROE, respectively, in the first rate year covering the period May 1, 2016 – April 30, 2017. The earnings sharing levels increase in rate year two (May 1, 2017 – April 30, 2018) to 9.65% , 10.15% and 10.65% ROE, respectively. The earnings sharing levels further increase in rate year three (May 1, 2018 – April 30, 2019) to 9.75% , 10.25% and 10.75% ROE, respectively. The rate plans also include the implementation of a rate adjustment mechanism (RAM) designed to return or collect certain defined reconciled revenues and costs, new depreciation rates, and continuation of the existing RDM for each company. On May 20, 2019, NYSEG and RG&E filed rate cases with the New York State Department of Public Service (NYDPS) for new tariffs. The effective date of new tariffs, assuming an approximately 11-month suspension period, will be April 20, 2020. The proposed rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as vegetation management, hardening/resiliency and emergency preparedness. The companies are requesting delivery revenues to be based on a 9.50% ROE and 50% equity ratio. The below table provides a summary of the proposed delivery rate increases, delivery revenue percentages and total revenue percentages for all four businesses: Requested Revenue Increase Delivery Revenue Total Revenue Utility (Millions) % % NYSEG Electric $ 156.7 20.4 % 10.4 % NYSEG Gas $ 6.3 3.0 % 1.4 % RG&E Electric $ 31.7 7.0 % 4.1 % RG&E Gas $ 5.8 3.3 % 1.4 % NYSEG and RG&E expect a decision in the rate cases at the end of the first quarter in 2020. We cannot predict the outcome of this matter. In December 2016, the Connecticut Public Utilities Regulatory Authority (PURA) approved new distribution rate schedules for The United Illuminating Company (UI) for three years, which became effective January 1, 2017, and which, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50% equity ratio, continued UI’s existing earnings sharing mechanism (ESM) pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year , continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist. In December 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018 for a three-year rate plan with rate increases of $1.5 million , $4.7 million and $5.0 million in 2018, 2019 and 2020, respectively. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism similar to the mechanisms authorized for Connecticut Natural Gas Corporation (CNG), ESM, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on a ROE of 9.25% and approximately 52% equity level. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist. On December 19, 2018, PURA approved a settlement agreement between CNG and the Office of Consumer Counsel and PURA prosecutorial staff that provides for new rates effective January 1, 2019. The settlement agreement included an increase in rates of $9.9 million in 2019, an increase of $4.6 million in 2020 and an increase of $5.2 million in 2021, for a total increase of $19.7 million over the three -year rate plan. The settlement agreement is based on an ROE of 9.30% and an equity ratio of 54.00% in 2019, 54.50% in 2020 and 55.00% in 2021. On January 18, 2019, the DPU approved a settlement agreement between BGC and the Massachusetts Attorney General’s Office providing for new distribution rates for BGC. The settlement agreement provides for a $1.6 million distribution base rate increase effective February 1, 2019 (with a make-whole provision back to January 1, 2019), and an additional $0.7 million base distribution increase effective November 1, 2019, if certain investments are made by BGC. The distribution rate increase is based on a 9.70% ROE and 55% equity ratio. The settlement agreement provides for the implementation of an RDM and pension expense tracker and also provides that BGC will not file to change base distribution rates to become effective before November 1, 2021. The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment. Regulatory assets as of June 30, 2019 and December 31, 2018 , respectively, consisted of: June 30, December 31, As of 2019 2018 (Millions) Pension and other post-retirement benefits cost deferrals $ 135 $ 141 Pension and other post-retirement benefits 1,083 1,138 Storm costs 342 346 Rate adjustment mechanism 16 18 Reliability support services 2 13 Revenue decoupling mechanism 10 7 Transmission revenue reconciliation mechanism 5 11 Contracts for differences 97 97 Hardship programs 26 26 Plant decommissioning 8 11 Deferred purchased gas 1 37 Deferred transmission expense 2 11 Environmental remediation costs 286 278 Debt premium 102 118 Unamortized losses on reacquired debt 23 23 Unfunded future income taxes 365 371 Federal tax depreciation normalization adjustment 155 157 Asset retirement obligation 18 18 Deferred meter replacement costs 28 29 Other 97 95 Total regulatory assets 2,801 2,945 Less: current portion 247 299 Total non-current regulatory assets $ 2,554 $ 2,646 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. The recovery of these amounts will be determined in future proceedings. “Storm costs” for CMP, NYSEG, RG&E and UI are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer service restoration costs resulting from major storms when they meet certain criteria for severity and duration. As of June 30, 2019 , deferred storm costs include $84 million and $51 million at NYSEG being recovered over ten -year and five -year periods, respectively, from the approval of the Joint Proposal by the NYPSC, and $143 million and $52 million at NYSEG and RG&E, respectively, not included in the Joint Proposal. The recovery of amounts not included in the Joint Proposal will be determined in future proceedings. “Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters. “Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt. “Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base. “Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. Following the approval of the Joint Proposal by the NYPSC, these amounts will be collected over a period of fifty years, and the NYPSC staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances. “Asset retirement obligations” (ARO) represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rate years covering 2011 forward. The recovery period in New York is from 27 to 39 years and for CMP this will be determined in future MPUC rate proceedings. “Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates. “Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments. “Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates. “Contracts for Differences” (CfDs) represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability. “Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements. “Rate adjustment mechanism” represents an interim rate change to return or collect certain defined reconciled revenues and costs for NYSEG and RG&E following the approval of the Joint Proposal by the NYPSC. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve month period. “Reliability support services” represents the difference between actual expenses for reliability support services and the amount provided for in rates. “Other” includes post term amortization deferrals and various items subject to reconciliation including rate change levelization and loss on re-acquired debt. Regulatory liabilities as of June 30, 2019 and December 31, 2018 , respectively, consisted of: June 30, December 31, As of 2019 2018 (Millions) Energy efficiency portfolio standard $ 73 $ 56 Gas supply charge and deferred natural gas cost 17 4 Pension and other post-retirement benefits cost deferrals 98 97 Carrying costs on deferred income tax bonus depreciation 60 72 Carrying costs on deferred income tax - Mixed Services 263(a) 18 20 2017 Tax Act 1,547 1,509 Revenue decoupling mechanism 21 19 Accrued removal obligations 1,169 1,153 Asset sale gain account 10 10 Economic development 29 28 Positive benefit adjustment 38 39 Theoretical reserve flow thru impact 16 19 Deferred property tax 41 25 Net plant reconciliation 22 19 Debt rate reconciliation 58 49 Rate refund – FERC ROE proceeding 30 29 Transmission congestion contracts 23 21 Merger-related rate credits 17 18 Accumulated deferred investment tax credits 14 14 Asset retirement obligation 13 13 Earning sharing provisions 18 17 Middletown/Norwalk local transmission network service collections 20 19 Low income programs 35 38 Non-firm margin sharing credits 16 10 Other 139 129 Total regulatory liabilities 3,542 3,428 Less: current portion 256 205 Total non-current regulatory liabilities $ 3,286 $ 3,223 “Energy efficiency portfolio standard” represents the difference between revenue billed to customers through an energy efficiency charge and the costs of our energy efficiency programs as approved by the state authorities. This may be refunded to customers within the next year. “Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant. “Asset sale gain account” represents the net gain on the sale of certain assets that will be used for the future benefit of ratepayers. The amortization period for the majority of the balance will be determined in future proceedings. “Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “Economic development” represents the economic development program which enables NYSEG and RG&E to foster economic development through attraction, expansion and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “Pension and other postretirement benefits” represent the actuarial gains on other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future expenses. Because no funds have yet been received for this, a regulatory liability is not reflected within the rate base. They also represent the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. Recovery of these amounts will be determined in future proceedings. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. The amortization period is five years following the approval of the Joint Proposal by the NYPSC and included in the Ginna RSSA settlement. “Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. "Debt rate reconciliation" represents the over/under collection of costs related to debt instruments identified in the rate case. Costs would include interest, commissions and fees versus amounts included in rates. “2017 Tax Act” represents the impact from remeasurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates from 35% to 21% under the provisions of the Tax Act will result in amounts previously and currently collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA and DPU have instituted separate proceedings in New York, Maine, Connecticut and Massachusetts, respectively, to review and address the implications associated with the Tax Act on the utilities providing service in such states. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During the three and six months ended June 30, 2019 , respectively, $0 and $1 million of rate credits were applied against customer bills. During the three and six months ended June 30, 2018 , $1 million and $2 million of rate credits were applied against customer bills. “Low income programs” represent various hardship and payment plan programs approved for recovery. “Other” includes cost of removal being amortized through rates and various items subject to reconciliation including Medicare subsidy benefits and stray voltage collections. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments and Fair Value Measurements | 6 Months Ended |
Jun. 30, 2019 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments and Fair Value Measurements | two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 2.92 $ 4.90 $ 2.14 Indiana hub ($/MWh) $ 30.66 $ 61.12 $ 19.10 Mid C ($/MWh) $ 24.86 $ 105.00 $ (0.50 ) Minn hub ($/MWh) $ 25.22 $ 52.17 $ 12.51 NoIL hub ($/MWh) $ 27.46 $ 55.39 $ 15.50 Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2024 and 2032, respectively. The gas swaps are used to hedge both gas inventory in firm storage and merchant wind positions. The power swaps are used to hedge merchant wind production in the West and Midwest. We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years . The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The gas swaps are economic hedges of merchant generation, with decreases in gas prices resulting in unrealized gains and increases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity. Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the models themselves. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products. Transactions are valued in part on the basis of forward price, correlation and volatility curves. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction. The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extended over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input June 30, 2019 Risk of non-performance 0.14% - 0.54% Discount rate 1.76% - 1.87% Forward pricing ($ per KW-month) $3.80 - $7.03 Fair Value of Debt As of June 30, 2019 and December 31, 2018 , debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt amounted to $7,276 million and $5,952 million as of June 30, 2019 and December 31, 2018 , respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the credit ratings of the borrowers in each case. All debt is considered Level 2 within the fair value hierarchy. On January 15, 2019, UI, CNG, SCG and BGC issued $195 million in aggregate amount of notes and bonds with maturity dates ranging from 2029 to 2049 and interest rates ranging from 4.07% to 4.52% . On April 1, 2019, NYSEG issued $12 million of Indiana County Industrial Development Authority Pollution Control Revenue Bonds in a private placement maturing in 2024 with a 2.65% interest rate. On May 16, 2019, we issued $750 million of senior unsecured notes maturing in 2029 at an interest rate of 3.80% . On June 3, 2019, CMP issued $240 million aggregate principal amount of first mortgage bonds with maturity dates ranging from 2026 to 2034 and interest rates ranging from 3.87% to 4.20% ." id="sjs-B4">Fair Value of Financial Instruments and Fair Value Measurements We determine the fair value of our derivative assets and liabilities and non-current equity investments associated with Networks’ activities utilizing market approach valuation techniques: • Our securities portfolio, consisting of Rabbi Trusts for deferred compensation plans, is primarily equity securities and money market funds. We measure the fair value of our securities portfolio using observable, unadjusted quoted market prices in active markets for identical assets and include the measurements in Level 1. • NYSEG and RG&E enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the NYISO. NYSEG and RG&E hedge approximately 70% of their electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value the companies’ open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value in Level 1. • NYSEG and RG&E enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange (NYMEX). Because we use prices quoted in an active market we include the fair value measurements in Level 1. • NYSEG, RG&E and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used, but because an unobservable basis adjustment is added to the forward prices, we include the fair value measurement for these contracts in Level 3. • UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs). We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical products with no adjustment are included in the Level 1 fair value. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX, foreign exchange swaps, and fixed price physical and basis and index trades are included in Level 2 fair value. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in Level 3 fair value. The unobservable inputs include historical volatilities and correlations for tolling arrangements and extrapolated values for certain power swaps. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. We determine the fair value of our interest rate swap derivative instruments based on a model whose inputs are observable, such as the London Interbank Offered Rate (LIBOR) forward interest rate curves. We include the fair value measurement for these contracts in Level 2 (See Note 7 for further discussion of interest rate swaps). We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2. The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate their estimated fair values and are considered Level 1. Restricted cash was $6 million and $7 million as of June 30, 2019 and December 31, 2018 , respectively, which is included in "Other Assets" on our condensed consolidated balance sheets. The financial instruments measured at fair value as of June 30, 2019 and December 31, 2018 , respectively, consisted of: As of June 30, 2019 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 35 $ — $ — $ — $ 35 Derivative assets Derivative financial instruments - power 10 27 123 (72 ) 88 Derivative financial instruments - gas — 20 37 (57 ) — Contracts for differences — — 2 — 2 Derivative financial instruments – other — 1 — — 1 Total 10 48 162 (129 ) 91 Derivative liabilities Derivative financial instruments - power (17 ) (49 ) (86 ) 111 (41 ) Derivative financial instruments - gas (3 ) (21 ) (8 ) 27 (5 ) Contracts for differences — — (99 ) — (99 ) Derivative financial instruments – other — (1 ) (1 ) — (2 ) Total $ (20 ) $ (71 ) $ (194 ) $ 138 $ (147 ) As of December 31, 2018 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 37 $ — $ — $ — $ 37 Derivative assets Derivative financial instruments - power 17 23 91 (59 ) 72 Derivative financial instruments - gas 1 20 36 (55 ) 2 Contracts for differences — — 5 — 5 Total 18 43 132 (114 ) 79 Derivative liabilities Derivative financial instruments - power (12 ) (41 ) (36 ) 77 (12 ) Derivative financial instruments - gas (1 ) (23 ) (7 ) 22 (9 ) Contracts for differences — — (102 ) — (102 ) Derivative financial instruments - other — (16 ) (2 ) — (18 ) Total $ (13 ) $ (80 ) $ (147 ) $ 99 $ (141 ) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and six months ended June 30, 2019 and 2018 , respectively, is as follows: Three Months Ended June 30, Six Months Ended June 30, (Millions) 2019 2018 2019 2018 Fair Value Beginning of Period, $ (22 ) $ (9 ) $ (15 ) $ 6 Gains recognized in operating revenues 14 9 37 14 (Losses) recognized in operating revenues — (2 ) (11 ) (6 ) Total gains recognized in operating revenues 14 7 26 8 Gains recognized in OCI 1 2 — — (Losses) recognized in OCI — — (13 ) — Total gains recognized in OCI 1 2 (13 ) — Net change recognized in regulatory assets and liabilities 2 3 — (8 ) Purchases (26 ) (1 ) (26 ) (3 ) Settlements (1 ) (3 ) (4 ) (4 ) Fair Value as of June 30, $ (32 ) $ (1 ) $ (32 ) $ (1 ) Gains for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ 14 $ 7 $ 26 $ 8 For assets and liabilities that are recognized in the condensed consolidated financial statements at fair value on a recurring basis, we determine whether transfers have occurred between levels in the hierarchy by re-assessing categorization based on the lowest level of input that is significant to the fair value measurement as a whole at the end of each reporting period. There have been no transfers between Level 1 and Level 2 during the periods reported. Level 3 Fair Value Measurement The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives. As of June 30, 2019 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps with delivery period > two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 2.92 $ 4.90 $ 2.14 Indiana hub ($/MWh) $ 30.66 $ 61.12 $ 19.10 Mid C ($/MWh) $ 24.86 $ 105.00 $ (0.50 ) Minn hub ($/MWh) $ 25.22 $ 52.17 $ 12.51 NoIL hub ($/MWh) $ 27.46 $ 55.39 $ 15.50 Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2024 and 2032, respectively. The gas swaps are used to hedge both gas inventory in firm storage and merchant wind positions. The power swaps are used to hedge merchant wind production in the West and Midwest. We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years . The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The gas swaps are economic hedges of merchant generation, with decreases in gas prices resulting in unrealized gains and increases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity. Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the models themselves. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products. Transactions are valued in part on the basis of forward price, correlation and volatility curves. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction. The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extended over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input June 30, 2019 Risk of non-performance 0.14% - 0.54% Discount rate 1.76% - 1.87% Forward pricing ($ per KW-month) $3.80 - $7.03 Fair Value of Debt As of June 30, 2019 and December 31, 2018 , debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt amounted to $7,276 million and $5,952 million as of June 30, 2019 and December 31, 2018 , respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the credit ratings of the borrowers in each case. All debt is considered Level 2 within the fair value hierarchy. On January 15, 2019, UI, CNG, SCG and BGC issued $195 million in aggregate amount of notes and bonds with maturity dates ranging from 2029 to 2049 and interest rates ranging from 4.07% to 4.52% . On April 1, 2019, NYSEG issued $12 million of Indiana County Industrial Development Authority Pollution Control Revenue Bonds in a private placement maturing in 2024 with a 2.65% interest rate. On May 16, 2019, we issued $750 million of senior unsecured notes maturing in 2029 at an interest rate of 3.80% . On June 3, 2019, CMP issued $240 million aggregate principal amount of first mortgage bonds with maturity dates ranging from 2026 to 2034 and interest rates ranging from 3.87% to 4.20% . |
Derivative Instruments and Hedg
Derivative Instruments and Hedging | 6 Months Ended |
Jun. 30, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging | Derivative Instruments and Hedging Our Networks and Renewables activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on our condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities. (a) Networks activities The tables below present Networks' derivative positions as of June 30, 2019 and December 31, 2018 , respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets: As of June 30, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 8 $ 4 $ 8 $ 2 Derivative liabilities (8 ) (2 ) (24 ) (95 ) — 2 (16 ) (93 ) Designated as hedging instruments Derivative assets 1 — — — Derivative liabilities — — (1 ) — 1 — (1 ) — Total derivatives before offset of cash collateral 1 2 (17 ) (93 ) Cash collateral receivable — — 6 4 Total derivatives as presented in the balance sheet $ 1 $ 2 $ (11 ) $ (89 ) As of December 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 18 $ 6 $ 10 $ 3 Derivative liabilities (10 ) (3 ) (21 ) (93 ) 8 3 (11 ) (90 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (2 ) — — — (2 ) — Total derivatives before offset of cash collateral 8 3 (13 ) (90 ) Cash collateral receivable — — — — Total derivatives as presented in the balance sheet $ 8 $ 3 $ (13 ) $ (90 ) The net notional volumes of the outstanding derivative instruments associated with Networks activities as of June 30, 2019 and December 31, 2018 , respectively, consisted of: June 30, December 31, As of 2019 2018 (Millions) Wholesale electricity purchase contracts (MWh) 4.5 4.9 Natural gas purchase contracts (Dth) 7.0 7.8 Fleet fuel purchase contracts (Gallons) 2.1 2.1 Derivatives not designated as hedging instruments NYSEG and RG&E have an electric commodity charge that passes through rates costs for the market price of electricity. We use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and /or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations. NYSEG and RG&E have purchased gas adjustment clauses that allow us to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities in accordance with the accounting requirements for regulated operations. The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of June 30, 2019 and December 31, 2018 and amounts reclassified from regulatory assets and liabilities into income for the three and six months ended June 30, 2019 and 2018 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of Three Months Ended June 30, Six Months Ended June 30, June 30, 2019 Electricity Natural Gas 2019 Electricity Natural Gas Electricity Natural Gas Regulatory assets $ 7 $ 3 Purchased power, natural gas and fuel used $ 6 $ — $ 10 $ — December 31, 2018 2018 Regulatory assets $ — $ — Purchased power, natural gas and fuel used $ 1 $ — $ (5 ) $ 2 Regulatory liabilities $ 5 $ — Pursuant to a PURA order, UI and Connecticut’s other electric utility, The Connecticut Light and Power Company (CL&P), each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers. PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of June 30, 2019 , UI has recorded a gross derivative asset of $2 million ( $0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $97 million , a gross derivative liability of $99 million ( $96 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0 . As of December 31, 2018 , UI had recorded a gross derivative asset of $5 million ( $0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $97 million , a gross derivative liability of $102 million ( $96 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0 . The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three and six months ended June 30, 2019 and 2018 , respectively, were as follows: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (Millions) Derivative assets $ (2 ) $ (2 ) $ (3 ) $ (4 ) Derivative liabilities $ 4 $ 6 $ 3 $ (3 ) Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, (Loss) Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Interest rate contracts $ — Interest expense $ 2 $ 76 Commodity contracts (1 ) Purchased power, natural gas and fuel used — 259 Foreign currency exchange contracts 1 — Total $ — $ 2 2018 Interest rate contracts $ — Interest expense $ 2 $ 70 Commodity contracts — Purchased power, natural gas and fuel used — 279 Total $ — $ 2 Six Months Ended June 30, Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Interest rate contracts $ — Interest expense $ 4 $ 154 Commodity contracts — Purchased power, natural gas and fuel used — 822 Foreign currency exchange contracts 1 — Total $ 1 $ 4 2018 Interest rate contracts $ — Interest expense $ 4 $ 144 Commodity contracts — Purchased power, natural gas and fuel used — 855 Total $ — $ 4 (a) Changes in accumulated OCI are reported on a pre-tax basis. On June 20, 2019, Networks entered into a forward contract to hedge the foreign currency exchange risk of approximately $100 million in forecasted capital expenditures through June 2023. The forward foreign currency contracts are designated and qualify as cash flow hedges and are expected to be settled upon the payment to vendors for capital expenditures. The gain or loss on the foreign exchange derivative is reported as a component of accumulated OCI and will be reclassified into earnings over the useful life of the underlying capital expenditures. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $57 million and $61 million as of June 30, 2019 and December 31, 2018 , respectively. We recorded $2 million and $4 million in net derivative losses related to discontinued cash flow hedges for both the three and six months ended June 30, 2019 and 2018 . We will amortize approximately $2 million of discontinued cash flow hedges for the remainder of 2019 . The unrealized loss of $1 million on hedge derivatives is reported in OCI because the forecasted transaction is considered to be probable as of June 30, 2019 . We expect that $1 million of those losses will be reclassified into earnings within the next twelve months . The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twelve months . (b) Renewables activities We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets. We also enter into tolling arrangements to sell the output of our thermal generation facilities. Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets. Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed-price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed-price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms. The net notional volumes of outstanding derivative instruments associated with Renewables activities as of June 30, 2019 and December 31, 2018 , respectively, consisted of: June 30, December 31, As of 2019 2018 (MWh/Dth in millions) Wholesale electricity purchase contracts 5 5 Wholesale electricity sales contracts 12 6 Natural gas and other fuel purchase contracts 35 29 Financial power contracts 11 11 Basis swaps – purchases 46 42 Basis swaps – sales 1 4 The fair values of derivative contracts associated with Renewables activities as of June 30, 2019 and December 31, 2018 , respectively, consisted of: June 30, December 31, As of 2019 2018 (Millions) Wholesale electricity purchase contracts $ 28 $ 11 Wholesale electricity sales contracts (52 ) (12 ) Natural gas and other fuel purchase contracts (3 ) (2 ) Financial power contracts 71 55 Basis swaps – purchases (2 ) (6 ) Total $ 42 $ 46 The tables below present Renewables' derivative positions as of June 30, 2019 and December 31, 2018 , respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets: As of June 30, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 23 $ 121 $ 41 $ 9 Derivative liabilities (2 ) (8 ) (58 ) (32 ) 21 113 (17 ) (23 ) Designated as hedging instruments Derivative assets — 1 3 9 Derivative liabilities — (5 ) (10 ) (49 ) — (4 ) (7 ) (40 ) Total derivatives before offset of cash collateral 21 109 (24 ) (63 ) Cash collateral receivable (payable) (10 ) (32 ) 11 30 Total derivatives as presented in the balance sheet $ 11 $ 77 $ (13 ) $ (33 ) As of December 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 19 $ 96 $ 29 $ 17 Derivative liabilities (5 ) (3 ) (48 ) (35 ) 14 93 (19 ) (18 ) Designated as hedging instruments Derivative assets 2 1 2 4 Derivative liabilities — — (7 ) (10 ) 2 1 (5 ) (6 ) Total derivatives before offset of cash collateral 16 94 (24 ) (24 ) Cash collateral receivable (payable) (8 ) (34 ) 9 17 Total derivatives as presented in the balance sheet $ 8 $ 60 $ (15 ) $ (7 ) Derivatives not designated as hedging instruments The effects of trading and non-trading derivatives associated with Renewables activities for the three and six months ended June 30, 2019 , consisted of: Three Months Ended Six Months Ended June 30, 2019 June 30, 2019 Trading Non-trading Total amount per income statement Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (2 ) $ — $ (1 ) $ — Wholesale electricity sales contracts 2 4 2 (5 ) Financial power contracts 1 22 — 9 Financial and natural gas contracts — 2 (1 ) — Total gain included in operating revenues $ 1 $ 28 $ 1,400 $ — $ 4 $ 3,242 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (3 ) $ — $ 17 Wholesale electricity sales contracts — — — — Financial power contracts — (3 ) — (2 ) Financial and natural gas contracts — (3 ) — 4 Total (loss) gain included in purchased power, natural gas and fuel used $ — $ (9 ) $ 259 $ — $ 19 $ 822 Total Gain $ 1 $ 19 $ — $ 23 The effects of trading and non-trading derivatives associated with Renewables activities for the three and six months ended June 30, 2018 , consisted of: Three Months Ended Six Months Ended June 30, 2018 June 30, 2018 (Millions) Trading Non-trading Trading Non-trading Wholesale electricity purchase contracts $ 5 $ 3 $ 6 $ 4 Wholesale electricity sales contracts (2 ) (7 ) (1 ) (7 ) Financial power contracts (1 ) (2 ) (2 ) 1 Financial and natural gas contracts — (1 ) 3 4 Total Gain (Loss) $ 2 $ (7 ) $ 6 $ 2 Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, Gain Recognized in OCI on Derivatives (a) Location of (Gain) Reclassified from Accumulated OCI into Income (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Commodity contracts $ 5 Operating revenues $ — $ 1,400 2018 Commodity contracts $ — Operating revenues $ (1 ) $ 1,402 Six Months Ended June 30, (Loss) Recognized in OCI on Derivatives (a) Location of (Gain) Reclassified from Accumulated OCI into Income (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Commodity contracts $ (15 ) Operating revenues $ — $ 3,242 2018 Commodity contracts $ (1 ) Operating revenues $ (20 ) $ 3,267 (a) Changes in OCI are reported on a pre-tax basis. Amounts are reclassified from accumulated OCI into income in the period during which the transaction being hedged affects earnings or when it becomes probable that a forecasted transaction being hedged would not occur. Notwithstanding future changes in prices, approximately $ 6 million of loss included in accumulated OCI at June 30, 2019 , is expected to be reclassified into earnings within the next twelve months. We did not record any net derivative losses related to discontinued cash flow hedges for both the three and six months ended June 30, 2019 and 2018. (c) Interest rate swaps AVANGRID uses financial derivative instruments from time to time to alter its fixed and floating rate debt balances or to hedge fixed rates in anticipation of future fixed rate issuances. In May 2019, we settled interest rate swaps designated as cash flow hedges related to the issuance of the $750 million in debt described in Note 6. The net loss in accumulated OCI related to these interest rate swaps is $39 million as of June 30, 2019. We amortized into income $0.5 million of the loss related to the settled interest rate swaps for both the three and six months ended June 30, 2019 . We will amortize approximately $2 million of the net loss on the interest rate swaps for the remainder of 2019 . The table below presents our interest rate swap derivative positions as of June 30, 2019 and December 31, 2018 , respectively, including the location of the net derivative positions on our condensed consolidated balance sheets: As of June 30, 2019 Current Liabilities (Millions) Designated as hedging instruments Derivative liabilities $ — As of December 31, 2018 Designated as hedging instruments Derivative liabilities $ (16 ) The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, Loss Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Interest rate contracts $ (4 ) Interest expense $ — $ 76 2018 Interest rate contracts $ (4 ) Interest expense $ — $ 70 Six Months Ended June 30, Loss Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Interest rate contracts $ (24 ) Interest expense $ — $ 154 2018 Interest rate contracts $ (4 ) Interest expense $ — $ 144 (a) Changes in OCI are reported on a pre-tax basis. The amount in accumulated OCI is being reclassified into earnings over the underlying debt maturity period which ends in 2029. (d) Counterparty credit risk management NYSEG and RG&E face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are applicable based on the respective counterparty’s or the counterparty guarantor’s credit rating, as provided by Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold. The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit rating on senior debt were to fall below investment grade. If such an event had occurred as of June 30, 2019 , UI would have had to post an aggregate of approximately $12 million in collateral. We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of a default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. The amounts of cash collateral under master netting arrangements that have not been offset against net derivative positions were $12 million and $26 million as of June 30, 2019 and December 31, 2018 , respectively. Derivative instruments settlements and collateral payments are included throughout the “Changes in operating assets and liabilities” section of operating activities in our condensed consolidated statements of cash flows. Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of June 30, 2019 is $10 million , for which we have posted collateral. |
Leases Leases
Leases Leases | 6 Months Ended |
Jun. 30, 2019 | |
Leases [Abstract] | |
Leases | Leases We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation, and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 64 years , some of which may include options to extend the leases for up to 32 years , and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option. The components of lease cost and other information related to leases as of and for the three and six months ended June 30, 2019 were as follows: Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 3 $ 6 Interest on lease liabilities 1 2 Total finance lease cost 4 8 Operating lease cost 3 8 Short-term lease cost 1 2 Variable lease cost 1 1 Total lease cost $ 9 $ 19 As of June 30, 2019 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 77 Operating lease liabilities, current 11 Operating lease liabilities, long-term 69 Total operating lease liabilities $ 80 Finance Leases Other assets $ 139 Other current liabilities 8 Other non-current liabilities 55 Total finance lease liabilities $ 63 Weighted-average Remaining Lease Term (years): Finance leases 8.01 Operating leases 13.08 Weighted-average Discount Rate: Finance leases 5.50 % Operating leases 3.68 % For the six months ended June 30, 2019 , supplemental cash flow information related to leases was as follows: Six Months Ended June 30, 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 6 Operating cash flows from finance leases $ 2 Financing cash flows from finance leases $ 25 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ — Operating leases $ (1 ) As of June 30, 2019 , maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, July 1, 2019 - December 31, 2019 $ 3 $ 7 2020 10 14 2021 6 13 2022 2 10 2023 50 8 Thereafter 4 56 Total lease payments 75 108 Less: imputed interest (12 ) (28 ) Total $ 63 $ 80 Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $49 million at both June 30, 2019 and December 31, 2018 . In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10 . The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25 -year life of the facility. Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. We used the incremental borrowing rate on January 1, 2019, for operating leases that commenced prior to that date. Comparative 2018 and 2017 Leases Disclosures The following are the 2018 annual lease disclosures, presented in accordance with ASC 840. Operating lease expense relating to operational facilities, office building leases and vehicle and equipment leases was $59 million , $72 million and $71 million for the years ended December 31, 2018, 2017 and 2016, respectively. Amounts related to contingent payments predominantly linked to electricity generation at the respective facilities were $11 million , $19 million and $22 million for the years ended December 31, 2018, 2017 and 2016, respectively. Leases for most of the land on which wind farm facilities are located have various renewal and termination clauses. On January 16, 2014, as required by the NYPSC, NYSEG renewed a Reliability Support Services Agreement (RSS Agreement) with Cayuga Operating Company, LLC (Cayuga) for Cayuga to provide reliability support services to maintain necessary system reliability through June 2017. Cayuga owns and operates the Cayuga Generating Facility (Facility), a coal-fired generating station that includes two generating units. Cayuga operates and maintains the RSS units and manages and complies with scheduling deadlines and requirements for maintaining the Facility and the RSS units as eligible energy and capacity providers and complies with dispatch instructions. NYSEG paid Cayuga a monthly fixed price and also paid for capital expenditures for specified capital projects. NYSEG was entitled to a share of any capacity and energy revenues earned by Cayuga. We accounted for this arrangement as an operating lease. The net expense incurred under this operating lease was $18 million for the year ended December 31, 2017, and $38 million for the year ended December 31, 2016. On October 21, 2015, RG&E, GNPP and multiple intervenors filed a joint proposal with the regulator for approval of the modified RSS Agreement for the continued operation of the Ginna Facility. On February 23, 2016, the NYPSC unanimously adopted the joint proposal, which provided for a term of the RSSA from April 1, 2015, through March 31, 2017 and RG&E monthly payments to GNPP in the amount of $15 million . RG&E was entitled to 70% of revenues from GNPP’s sales into the energy and capacity markets, while GNPP was entitled to 30% of such revenues. We accounted for this arrangement as an operating lease. The net expense incurred under this operating lease was $6 million for the year ended December 31, 2017, and $115 million for the year ended December 31, 2016. Total future minimum lease payments as of December 31, 2018 consisted of: Year Operating Leases Capital Leases Total (Millions) 2019 $ 31 $ 30 $ 61 2020 39 10 49 2021 38 7 45 2022 35 2 37 2023 33 50 83 Thereafter 735 2 737 Total $ 911 $ 101 $ 1,012 |
Leases | Leases We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation, and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 64 years , some of which may include options to extend the leases for up to 32 years , and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option. The components of lease cost and other information related to leases as of and for the three and six months ended June 30, 2019 were as follows: Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 3 $ 6 Interest on lease liabilities 1 2 Total finance lease cost 4 8 Operating lease cost 3 8 Short-term lease cost 1 2 Variable lease cost 1 1 Total lease cost $ 9 $ 19 As of June 30, 2019 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 77 Operating lease liabilities, current 11 Operating lease liabilities, long-term 69 Total operating lease liabilities $ 80 Finance Leases Other assets $ 139 Other current liabilities 8 Other non-current liabilities 55 Total finance lease liabilities $ 63 Weighted-average Remaining Lease Term (years): Finance leases 8.01 Operating leases 13.08 Weighted-average Discount Rate: Finance leases 5.50 % Operating leases 3.68 % For the six months ended June 30, 2019 , supplemental cash flow information related to leases was as follows: Six Months Ended June 30, 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 6 Operating cash flows from finance leases $ 2 Financing cash flows from finance leases $ 25 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ — Operating leases $ (1 ) As of June 30, 2019 , maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, July 1, 2019 - December 31, 2019 $ 3 $ 7 2020 10 14 2021 6 13 2022 2 10 2023 50 8 Thereafter 4 56 Total lease payments 75 108 Less: imputed interest (12 ) (28 ) Total $ 63 $ 80 Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $49 million at both June 30, 2019 and December 31, 2018 . In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10 . The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25 -year life of the facility. Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. We used the incremental borrowing rate on January 1, 2019, for operating leases that commenced prior to that date. Comparative 2018 and 2017 Leases Disclosures The following are the 2018 annual lease disclosures, presented in accordance with ASC 840. Operating lease expense relating to operational facilities, office building leases and vehicle and equipment leases was $59 million , $72 million and $71 million for the years ended December 31, 2018, 2017 and 2016, respectively. Amounts related to contingent payments predominantly linked to electricity generation at the respective facilities were $11 million , $19 million and $22 million for the years ended December 31, 2018, 2017 and 2016, respectively. Leases for most of the land on which wind farm facilities are located have various renewal and termination clauses. On January 16, 2014, as required by the NYPSC, NYSEG renewed a Reliability Support Services Agreement (RSS Agreement) with Cayuga Operating Company, LLC (Cayuga) for Cayuga to provide reliability support services to maintain necessary system reliability through June 2017. Cayuga owns and operates the Cayuga Generating Facility (Facility), a coal-fired generating station that includes two generating units. Cayuga operates and maintains the RSS units and manages and complies with scheduling deadlines and requirements for maintaining the Facility and the RSS units as eligible energy and capacity providers and complies with dispatch instructions. NYSEG paid Cayuga a monthly fixed price and also paid for capital expenditures for specified capital projects. NYSEG was entitled to a share of any capacity and energy revenues earned by Cayuga. We accounted for this arrangement as an operating lease. The net expense incurred under this operating lease was $18 million for the year ended December 31, 2017, and $38 million for the year ended December 31, 2016. On October 21, 2015, RG&E, GNPP and multiple intervenors filed a joint proposal with the regulator for approval of the modified RSS Agreement for the continued operation of the Ginna Facility. On February 23, 2016, the NYPSC unanimously adopted the joint proposal, which provided for a term of the RSSA from April 1, 2015, through March 31, 2017 and RG&E monthly payments to GNPP in the amount of $15 million . RG&E was entitled to 70% of revenues from GNPP’s sales into the energy and capacity markets, while GNPP was entitled to 30% of such revenues. We accounted for this arrangement as an operating lease. The net expense incurred under this operating lease was $6 million for the year ended December 31, 2017, and $115 million for the year ended December 31, 2016. Total future minimum lease payments as of December 31, 2018 consisted of: Year Operating Leases Capital Leases Total (Millions) 2019 $ 31 $ 30 $ 61 2020 39 10 49 2021 38 7 45 2022 35 2 37 2023 33 50 83 Thereafter 735 2 737 Total $ 911 $ 101 $ 1,012 |
Contingencies
Contingencies | 6 Months Ended |
Jun. 30, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contingencies | Contingencies We are party to various legal disputes arising as part of our normal business activities. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency. Transmission - ROE Complaint – CMP and UI On September 30, 2011, the Massachusetts Attorney General, DPU, PURA, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a joint complaint with the FERC pursuant to sections 206 and 306 of the Federal Power Act, against several New England Transmission Owners (NETOs) claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE with refunds to customers for the 15-month refund periods beginning October 1, 2011 (Complaint I), December 27, 2012 (Complaint II), July 31, 2014 (Complaint III) and April 29, 2016 (Complaint IV). On October 16, 2014, the FERC issued its decision in Complaint I setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19% . The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners. CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $24 million and $6 million , respectively, as of June 30, 2019 , which has not changed since December 31, 2018 , except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge would be an additional aggregate reserve for Complaints II and III of $17 million , which is based upon currently available information for these proceedings. Following various intermediate hearings, orders and appellate decisions, on October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs’ transmission formula rate on file at the FERC (the October 2018 Order). The FERC proposes to use this new methodology to resolve Complaints I, II, III and IV filed by the New England state consumer advocates. The new proposed ROE methodology set forth in the October 2018 Order considers more than just the two-step discounted cash flow (DCF) analysis adopted in the FERC order on Complaint I vacated by the Court. The new proposed ROE methodology uses three financial analyses (i.e., DCF, the capital-asset pricing model and the expected earnings analysis) to produce a range of returns to narrow the zone of reasonableness when assessing whether a complainant has met its initial burden of demonstrating that the utility’s existing ROE is unjust and unreasonable. The new proposed ROE methodology establishes a range of just and reasonable ROEs of 9.60% to 10.99% and proposes a just and reasonable base ROE of 10.41% with a new ROE cap of 13.08% . Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019 and replies to the initial briefs on March 8, 2019. We cannot predict the outcome of this proceeding. New York State Department of Public Service Investigation of the Preparation for and Response to the March 2017 Windstorm On March 11, 2017, the NYDPS commenced an investigation of NYSEG’s and RG&E’s preparation for and response to the March 2017 windstorm, which affected more than 219,000 NYSEG and RG&E customers. The NYDPS staff issued a report (the Staff Report) of the findings from their investigation on November 16, 2017. The Staff Report made several recommendations for future storm response and also alleged that NYSEG and RG&E had violated their own emergency response plan in a number of respects. Also on November 16, 2017, the NYPSC issued an Order Instituting Proceeding and to Show Cause (the Order) requiring the companies to address whether the NYPSC should mandate, reject or modify, in whole or in part the recommendations made in the Staff Report. The Order also required the companies to show cause why the NYPSC should not commence an administrative penalty proceeding. On May 18, 2018, NYSEG and RG&E filed a settlement joint proposal and investment joint proposal before the NYPSC to settle potential penalties and avoid litigation related to the March 2017 windstorm, pursuant to which, among other things, NYSEG and RG&E have agreed to make $4 million in investments designed to increase resiliency and improve emergency response in the areas impacted by the storm. The investments will not be reflected in rate base or operating expenses in establishing future delivery rates. On April 18, 2019, the NYPSC approved the joint proposals. New York State Department of Public Service Investigation of the Preparation for and Response to the March 2018 Winter Storms In March 2018, following two severe winter storms that impacted more than one million electric utility customers in New York, including 520,000 NYSEG and RG&E customers, the NYPSC initiated a comprehensive investigation of all the New York electric utilities’ preparation and response to those events. The investigation was expanded to include other 2018 New York spring storm events. On April 18, 2019 the NYDPS staff issued a report (the 2018 Staff Report) of the findings from their investigation. The 2018 Staff Report identifies 94 recommendations for corrective actions to be implemented in the utilities Emergency Response Plans (ERP). The report also identified potential violations by several of the utilities, including NYSEG and RG&E. Also on April 18, 2019, the NYPSC issued an Order Instituting Proceeding and to Show Cause directed to all major electric utilities in New York, including NYSEG and RG&E. The order directs the utilities, including NYSEG and RG&E, to show cause why the NYPSC should not pursue civil penalties, and / or administrative penalties for the apparent failure to follow their respective ERPs as approved and mandated by the NYPSC. The NYPSC also directs the utilities, within 30 days, to address whether the NYPSC should mandate, reject or modify in whole or in part, the 94 recommendations contained in the 2018 Staff Report. On May 20, 2019, NYSEG and RG&E responded to the portion of the Order to Show Cause with respect to the recommendations contained in the 2018 Staff Report. The Commission granted the companies an extension until August 2, 2019 to respond to the portion of the Order to Show Cause with respect to why the Commission should not pursue a penalty action. The companies and the Commission’s counsel have commenced settlement discussions. We cannot predict the final outcome of this matter. NYPSC Directs Counsel to Commence Judicial Enforcement Proceeding Against NYSEG On April 18, 2019, the NYPSC issued an Order Directing Counsel to the Commission to commence a special proceeding or an action in New York State Supreme Court to stop and prevent ongoing future violations by NYSEG of NYPSC regulations and orders. As of the date hereof, a special proceeding or an action has not been commenced; however, related to the Winter Storm Order to Show Cause, the companies and the Commission’s counsel have commenced settlement discussions. We cannot predict the final outcome of this matter. California Energy Crisis Litigation Two California agencies brought a complaint in 2001 against a long-term power purchase agreement entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the power purchase agreement were unjust and unreasonable. The FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed the FERC's dismissal of Renewables from the proceeding. Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate court for further consideration in light of the Supreme Court’s decision in a similar case. In light of the Supreme Court's order, on December 4, 2008, the Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the Supreme Court's rulings. In 2014, the FERC assigned an administrative law judge to conduct evidentiary hearings. Following discovery, the FERC trial staff recommended that the complaint against Renewables be dismissed. A hearing was held before a FERC administrative law judge in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016. The proposed ruling found no evidence that Renewables had engaged in any unlawful market conduct that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that the price of the power purchase agreements imposed an excessive burden on customers in the amount of $259 million . Renewables position, as presented at hearings and agreed by the FERC trial staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted briefs on exceptions to the administrative law judge’s proposed ruling to the FERC. There is not specific timetable for the FERC's ruling. In April 2018, Renewables requested, based on the nearly two years of delay from the preliminary proposed ruling and the Supreme Court precedent, that the FERC issue a final decision expeditiously. We cannot predict the outcome of this proceeding. Class Actions Regarding LDC Gas Transportation Service on Algonquin Gas Transmission Breiding et al. v. Eversource and Avangrid - Class Action . On November 16, 2017, a class action lawsuit was filed in the U.S. District Court for the District of Massachusetts on behalf of customers in New England against the Company and Eversource alleging that certain of their respective subsidiaries that take gas transportation service over the Algonquin Gas Transmission (AGT), which for AVANGRID would be its indirect subsidiaries SCG and CNG, engaged in pipeline capacity scheduling practices on AGT that resulted in artificially increased electricity prices in New England. These allegations were based on the conclusions of a whitepaper issued by the Environmental Defense Fund (EDF), an environmental advocacy organization, on October 10, 2017, purporting to analyze the relationship between the New England electricity market and the New England local gas distribution companies. The plaintiffs assert claims under federal antitrust law, state antitrust, unfair competition and consumer protection laws, and under the common law of unjust enrichment. They seek damages, disgorgement, restitution, injunctive relief, and attorney fees and costs. On February 27, 2018, the FERC released the results of a FERC staff inquiry into the pipeline capacity scheduling practices on the AGT. The inquiry arose out of the allegations made by the EDF in its whitepaper. The FERC announced that, based on an extensive review of public and non-public data, it had determined that the EDF study was flawed and led to incorrect conclusions. FERC also stated that the staff inquiry revealed no evidence of anticompetitive withholding of natural gas pipeline capacity on the AGT and that it would take no further action on the matter. On April 27, 2018, the Company filed a Motion to Dismiss all of the claims based on federal preemption and lack of any evidence of antitrust behavior, citing, among other reasons, the results of the FERC staff inquiry conclusion. The plaintiffs filed opposition to the motion to dismiss on May 25, 2018. On September 11, 2018, the District Court granted the Company’s Motion and dismissed all claims. On January 29, 2019, the plaintiffs filed a brief in support of appeal and on April 26, 2019, the Company and Eversource filed a joint brief in opposition. On May 17, 2019, the plaintiffs filed a reply to the opposition. Oral arguments were held on July 24, 2019. We cannot predict the outcome of this appeal. PNE Energy Supply LLC v. Eversource Energy and Avangrid, Inc. - Class Action . On August 10, 2018, PNE Energy Supply LLC, a competitive energy supplier located in New England that purchases electricity in the day-ahead and real time wholesale electric market, filed a civil antitrust action, on behalf of itself and those similarly situated, against the Company and Eversource alleging that their respective gas subsidiaries illegally manipulated the supply of pipeline capacity in the “secondary capacity market” in order to artificially inflate New England natural gas and electricity prices. These allegations were also based on the conclusions of the whitepaper issued by EDF. The plaintiff claims to represent entities who purchased electricity directly in the wholesale electricity market that it claims was targeted by the alleged anticompetitive conduct of Eversource and the Company. On September 28, 2018, the Company filed a Motion to Dismiss all of the claims based on federal preemption and lack of any evidence of antitrust behavior, citing, among other reasons, the results of the FERC staff inquiry and the dismissal of the related case, "Breiding et al. v. Eversource and Avangrid," by the same court in September. The plaintiffs filed opposition to the motion to dismiss on October 26, 2018 and the Company filed a reply on November 15, 2018. The district court heard oral arguments on the motion to dismiss on January 18, 2019. On April 26, 2019, the Company filed a brief in support of its motion to dismiss, and on June 7, 2019, the district court granted the Company’s Motion to Dismiss and dismissed all claims. On July 3, 2019, the plaintiffs filed notice of appeal in the U.S. Court of Appeals for the First Circuit. We cannot predict the outcome of this class action lawsuit. Yankee Nuclear Spent Fuel Disposal Claim CMP has an ownership interest in Maine Yankee Atomic Power Company, Connecticut Yankee Atomic Power Company and Yankee Atomic Electric Company (the Yankee Companies), three New England single-unit decommissioned nuclear reactor sites, and UI has an ownership interest in Connecticut Yankee Atomic Power Company. Pursuant to the statute of limitations, the Yankee Companies file a lawsuit periodically to recover damages from the Department of Energy (DOE) for breach of the Nuclear Spent Fuel Disposal Contract to remove spent nuclear fuel and greater than class C waste as required by contract. From 2012 to 2016 the Yankee Companies filed three claims against the DOE (Phase I, II and III) for the years from 1995 to 2012 and received damage awards, which flow through the Yankee Companies to shareholders (including CMP and UI based percentage of ownership) to reduce retail customer charges. On May 22, 2017, the Yankee Companies filed their next case (Phase IV) in the Federal Court of Claims (Court), seeking damages for the period from January 1, 2013 through December 31, 2016 and submitted their claimed Phase IV damages to the DOE in late August 2017. The Court issued its decision on the Phase IV trial on February 21, 2019, awarding the Yankee Companies a combined $103 million (Connecticut Yankee $41 million , Maine Yankee $34 million and Yankee Atomic $28 million ). The damage awards are returned to customers either through customer refunds or by reducing future costs. Refunds or reductions in costs are reflected in the Yankee Companies billings to shareholders, including CMP and UI. CMP and UI will receive their proportionate share of the awards that flow through based on percentage of ownership. On April 23, 2019, the notice of appeal period expired and the Phase IV trial award became final. Guarantee Commitments to Third Parties As of June 30, 2019 , we had approximately $513 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. These instruments provide financial assurance to the business and trading partners of AVANGRID and its subsidiaries in their normal course of business. The instruments only represent liabilities if AVANGRID or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of June 30, 2019 , neither we nor our subsidiaries have any liabilities recorded for these instruments. |
Environmental Liabilities
Environmental Liabilities | 6 Months Ended |
Jun. 30, 2019 | |
Environmental Remediation Obligations [Abstract] | |
Environmental Liabilities | Environmental Liabilities Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies. Waste sites The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-five waste sites, which do not include sites where gas was manufactured in the past. Fifteen of the twenty-five sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; six sites are included in Maine’s Uncontrolled Sites Program and one site is included on the Massachusetts Non-Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, nine of the twenty-five sites are also included on the National Priorities list. Any liability may be joint and several for certain sites. We have recorded an estimated liability of $5 million related to ten of the twenty-five sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $8 million related to another eleven sites where we believe it is probable that we will incur remediation costs and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. Our estimate for costs to remediate these sites ranges from $12 million to $21 million as of June 30, 2019 . Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the allocation of the clean-up costs. Manufactured Gas Plants We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Eight sites are included in the New York State Registry; three sites are included in the New York State Department of Environmental Conservation Multi-Site Order on Consent; three sites are part of Maine’s Voluntary Response Action Program with two such sites part of Maine’s Uncontrolled Sites Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites. Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $176 million to $417 million as of June 30, 2019 . Our estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial actions, changes in technology relating to remedial alternatives and changes to current laws and regulations. Certain of our Connecticut and Massachusetts regulated gas companies own or have previously owned properties where MGPs had historically operated. MGP operations have led to contamination of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is regulated by the federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations. Each of the companies has or had an ownership interest in one or more such properties contaminated as a result of MGP-related activities. Under the existing regulations, the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated. Finally, at some of these sites, the scope of the contamination has not yet been fully characterized; no liability was recorded related to these sites as of June 30, 2019 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites. As of June 30, 2019 and December 31, 2018 , the liability associated with our MGP sites in Connecticut, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates, was $98 million and $99 million , respectively. Our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $362 million and $366 million as of June 30, 2019 and December 31, 2018 , respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2055. FirstEnergy NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at sixteen former MGP sites, which are included in the discussion above. In July 2011, the District Court issued a decision and order in NYSEG’s favor, requiring FirstEnergy to pay NYSEG approximately $60 million for past and future clean-up costs at the sixteen sites in dispute. On September 9, 2011, FirstEnergy paid NYSEG $30 million , representing their share of past costs of $27 million and pre-judgment interest of $3 million . FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the District Court’s decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22 million , excluding interest, and reducing FirstEnergy’s allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in November 2014. FirstEnergy remains liable for a substantial share of clean up expenses at nine MGP sites. Based on current projections, FirstEnergy’s share is estimated at approximately $20 million . This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG customers. Century Indemnity and OneBeacon On August 14, 2013, NYSEG filed suit in federal court against two excess insurers, Century Indemnity and OneBeacon, who provided excess liability coverage to NYSEG. NYSEG seeks payment for clean-up costs associated with contamination at twenty-two former manufactured gas plants. Based on estimated clean-up costs of $282 million , the carriers’ allocable share could equal or exceed approximately $89 million , excluding pre-judgment interest, although this amount may change substantially depending upon the determination of various factual matters and legal issues during the case. Century Indemnity and OneBeacon have answered, admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s. On March 31, 2017, the District Court granted motions filed by Century Indemnity and One Beacon dismissing all of NYSEG’s claims against both defendants on the grounds of late notice. NYSEG filed a motion with the District Court on April 14, 2017 seeking reconsideration of the Court’s decision, which was denied by an order dated March 27, 2018. NYSEG filed a notice appealing the District Court’s dismissal on April 9, 2018. On April 25, 2019, the Second Circuit Court of Appeals affirmed the lower court’s dismissal of NYSEG’s claims. NYSEG filed a motion seeking en banc review on May 2, 2019, which was denied by the Second Circuit Court of Appeals on May 20, 2019. English Station In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then and current owners of a former generation site on the Mill River in New Haven (the English Station site) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut against UI seeking, among other things: (i) an order directing UI to reimburse the plaintiffs for costs they have incurred and will incur for the testing, investigation and remediation of hazardous substances at the English Station site and (ii) an order directing UI to investigate and remediate the site. This proceeding had been stayed in 2014 pending resolutions of other proceedings before the Connecticut Department of Energy and Environmental Protection (DEEP) concerning the English Station site. In December 2016, the court administratively closed the file without prejudice to reopen upon the filing of a motion to reopen by any party. In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i) remediation of the English Station site; (ii) reimbursement of remediation costs; (iii) termination of UI’s easement rights; (iv) reimbursement for costs associated with securing the property; and (v) punitive damages. This lawsuit had been stayed in May 2014 pending mediation. Due to lack of activity in the case, the court terminated the stay and scheduled a status conference for July 6, 2017. On July 5, 2017, Asnat filed a pretrial memorandum claiming damages of $10 million for “environmental remediation activities” and lost use of the property. On April 16, 2018, the plaintiffs filed a revised complaint alleging fraud and unjust enrichment against UIL and UI and adding former UIL officers as named defendants alleging fraud. The complaint was further revised on July 3, 2018. We filed a Motion to Strike the counts in the complaint in August 2018 and oral arguments were held. On February 21, 2019, the court granted our Motion to Strike with respect to all counts except for the count against UI for unjust enrichment. The counts stricken include all counts against the individual defendants as well as against UIL. As to the remaining count, the court declined to strike the claim against UI for unjust enrichment. The plaintiffs filed a motion to appeal the court's dismissal. We cannot predict the outcome of this matter. On April 8, 2013, DEEP issued an administrative order addressed to UI, Evergreen Power, Asnat and others, ordering the parties to take certain actions related to investigating and remediating the English Station site. Mediation of the matter began in the fourth quarter of 2013 and concluded unsuccessfully in April 2015. This proceeding was stayed while DEEP and UI continue to work through the remediation process pursuant to the consent order described below. Status reports are periodically filed with the DEEP. On August 4, 2016, DEEP issued a partial consent order (the consent order), that, subject to its terms and conditions, requires UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. Under the consent order, to the extent that the cost of this investigation and remediation is less than $30 million , UI will remit to the State of Connecticut the difference between such cost and $30 million to be used for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut and the Commissioner of DEEP. UI is obligated to comply with the terms of the consent order even if the cost of such compliance exceeds $30 million . Under the terms of the consent order, the State will discuss options with UI on recovering or funding any cost above $30 million such as through public funding or recovery from third parties; however, it is not bound to agree to or support any means of recovery or funding. UI has initiated its process to investigate and remediate the environmental conditions within the perimeter of the English Station site pursuant to the consent order. As of June 30, 2019 and December 31, 2018 , the amount reserved for this matter was $17 million and $20 million , respectively. We cannot predict the outcome of this matter. |
Post-retirement and Similar Obl
Post-retirement and Similar Obligations | 6 Months Ended |
Jun. 30, 2019 | |
Retirement Benefits [Abstract] | |
Post-retirement and Similar Obligations | Post-retirement and Similar Obligations We made $12 million and $19 million of pension contributions for the three and six months ended June 30, 2019 , respectively. We expect to make additional contributions of $46 million for the remainder of 2019 . The components of net periodic benefit cost for pension benefits for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (Millions) Service cost $ 10 $ 11 $ 20 $ 22 Interest cost 32 32 65 64 Expected return on plan assets (48 ) (50 ) (96 ) (100 ) Amortization of: Prior service costs (1 ) 1 (1 ) 1 Actuarial loss 27 37 57 75 Net Periodic Benefit Cost $ 20 $ 31 $ 45 $ 62 The components of net periodic benefit cost for postretirement benefits for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (Millions) Service cost $ — $ 1 $ 1 $ 2 Interest cost 4 5 8 9 Expected return on plan assets (2 ) (2 ) (4 ) (4 ) Amortization of: Prior service costs (2 ) (2 ) (4 ) (4 ) Actuarial loss (1 ) 2 (1 ) 3 Net Periodic Benefit Cost $ (1 ) $ 4 $ — $ 6 |
Equity
Equity | 6 Months Ended |
Jun. 30, 2019 | |
Equity [Abstract] | |
Equity | Equity As of June 30, 2019 , our share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,272 shares outstanding, 81.5% of which are owned by Iberdrola, each having a par value of $0.01 , for a total value of common stock of $3 million and additional paid in capital of $13,659 million . As of December 31, 2018 , our share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,272 shares outstanding, 81.5% of which were owned by Iberdrola, each having a par value of $0.01 , for a total value of common stock capital of $3 million and additional paid in capital of $13,657 million . We had 485,810 shares of common stock held in trust and no convertible preferred shares outstanding as of both June 30, 2019 and December 31, 2018 . During the three months ended June 30, 2019 and 2018 , we issued no shares of common stock and released no shares of common stock held in trust. During the six months ended June 30, 2019 we issued no shares of common stock and released no shares of common stock held in trust. During the six months ended June 30, 2018 , we issued 81,208 shares of common stock each having a par value of $0.01 and released no shares of common stock held in trust common stock. We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain the relative ownership percentage by Iberdrola at 81.5% . The stock repurchase program may be suspended or discontinued at any time upon notice. Out of a total of 261,058 treasury shares of common stock of AVANGRID as of June 30, 2019 , 115,831 shares were repurchased during 2016, 64,019 shares were repurchased during 2017 and 81,208 shares were repurchased during 2018, all in the open market. The total cost of all repurchases, including commissions, was $12 million as of June 30, 2019 . Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: As of March 31, Adoption of Three Months Ended June 30, As of June 30, As of March 31, Adoption of new accounting Three Months Ended June 30, As of June 30, 2019 standard 2019 2019 2018 standard 2018 2018 (Millions) Change in revaluation of defined benefit plans, net of income tax expense of $0.2 for 2018 $ (13 ) $ — $ — $ (13 ) $ (14 ) $ — $ 1 $ (13 ) Loss on nonqualified pension plans (6 ) — (1 ) (7 ) (7 ) — — (7 ) Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $0.5 for 2019 and $(1.5) for 2018 (20 ) — 2 (18 ) 30 — (5 ) 25 Reclassification to net income of losses on cash flow hedges, net of income tax expense of $0.2 for 2019(a) (72 ) — 1 (71 ) (66 ) — — (66 ) Gain (loss) on derivatives qualifying as cash flow hedges (92 ) — 3 (89 ) (36 ) — (5 ) (41 ) Accumulated Other Comprehensive (Loss) Gain $ (111 ) $ — $ 2 $ (109 ) $ (57 ) $ — $ (4 ) $ (61 ) As of December 31, Adoption of new accounting Six Months Ended June 30, As of June 30, As of December 31, Adoption of new accounting Six Months Ended June 30, As of June 30, 2018 standard 2019 2019 2017 standard 2018 2018 (Millions) Change in revaluation of defined benefit plans, net of income tax expense of $0.2 for 2018 $ (11 ) $ (2 ) $ — $ (13 ) $ (14 ) $ — $ 1 $ (13 ) Loss on nonqualified pension plans (6 ) — (1 ) (7 ) (6 ) (1 ) — (7 ) Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(10.4) for 2019 and $(1.5) for 2018 9 — (27 ) (18 ) 30 — (5 ) 25 Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $0.9 for 2019 and $(7.2) for 2018(a) (64 ) (10 ) 3 (71 ) (56 ) — (10 ) (66 ) Loss on derivatives qualifying as cash flow hedges (55 ) (10 ) (24 ) (89 ) (26 ) — (15 ) (41 ) Accumulated Other Comprehensive Loss $ (72 ) $ (12 ) $ (25 ) $ (109 ) $ (46 ) $ (1 ) $ (14 ) $ (61 ) ________________________ (a)Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income. |
Earnings Per Share
Earnings Per Share | 6 Months Ended |
Jun. 30, 2019 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Earnings Per Share Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the three and six months ended June 30, 2019 and 2018 , while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculation for the three months ended June 30, 2019 and for the six months ended June 30, 2019 and 2018 . The dilutive securities, which consist of performance and restricted units, did result in a change in our earnings per share calculation for the three months ended June 30, 2018. The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 110 $ 107 $ 327 $ 351 Denominator: Weighted average number of shares outstanding - basic 309,491,082 309,517,854 309,491,082 309,515,758 Weighted average number of shares outstanding - diluted 309,512,752 309,719,584 309,509,620 309,711,682 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.36 $ 0.35 $ 1.06 $ 1.13 Earnings Per Common Share, Diluted $ 0.36 $ 0.34 $ 1.06 $ 1.13 |
Segment Information
Segment Information | 6 Months Ended |
Jun. 30, 2019 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments: • Networks: includes all of the energy transmission and distribution activities, any other regulated activity originating in New York and Maine and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes eight rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment. • Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities. The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude restructuring charges, mark-to-market adjustments to reflect the effect of mark-to-market changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity, loss from held for sale measurement, accelerated depreciation derived from repowering of wind farms, income from release of collateral, impact of the Tax Act and adjustments for the non-core Gas storage business. Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in the condensed consolidated financial statements. Segment information as of and for the three and six months ended June 30, 2019 , consisted of: Three Months Ended June 30, 2019 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,092 $ 307 $ 1 $ 1,400 Revenue - intersegment 1 — (1 ) — Depreciation and amortization 135 87 — 222 Operating income 155 49 3 207 Earnings (losses) from equity method investments 2 (1 ) — 1 Interest expense, net of capitalization 66 2 7 76 Income tax expense (benefit) 25 (18 ) 22 29 Adjusted net income $ 66 $ 64 $ (29 ) $ 101 Included in revenue-external for the three months ended June 30, 2019 , are: $836 million from regulated electric operations, $254 million from regulated gas operations and $2 million from other operations of Networks; $307 million primarily from renewable energy generation of Renewables. Six Months Ended June 30, 2019 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 2,692 $ 549 $ 1 $ 3,242 Revenue - intersegment 5 — (5 ) — Depreciation and amortization 269 175 — 444 Operating income 486 62 — 548 Earnings (losses) from equity method investments 5 (3 ) — 2 Interest expense, net of capitalization 135 7 12 154 Income tax expense (benefit) 89 (17 ) (2 ) 70 Adjusted net income 267 69 (16 ) 319 Capital expenditures 678 659 — 1,337 As of June 30, 2019 Property, plant and equipment 15,104 9,261 8 24,373 Equity method investments 144 361 — 505 Total assets $ 22,491 $ 11,905 $ (1,255 ) $ 33,141 _________________________ (a) Includes Corporate, Gas and intersegment eliminations. Included in revenue-external for the six months ended June 30, 2019 , are: $1,800 million from regulated electric operations, $890 million from regulated gas operations and $2 million from other operations of Networks; $549 million primarily from renewable energy generation of Renewables. Segment information for the three and six months ended June 30, 2018 , consisted of: Three Months Ended June 30, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,103 $ 296 $ 3 $ 1,402 Revenue - intersegment 2 1 (3 ) — Loss from assets held for sale — — 10 10 Depreciation and amortization 128 87 — 215 Operating income (loss) 183 55 (16 ) 222 Earnings (losses) from equity method investments 4 1 — 5 Interest expense, net of capitalization 65 7 (2 ) 70 Income tax expense (benefit) 23 (24 ) 28 27 Adjusted net income $ 79 $ 68 $ (18 ) $ 128 Included in revenue-external for the three months ended June 30, 2018 , are: $864 million from regulated electric operations, $242 million from regulated gas operations and $(3) million from other operations of Networks; $296 million primarily from renewable energy generation of Renewables. Six Months Ended June 30, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 2,652 $ 579 $ 36 $ 3,267 Revenue - intersegment 5 2 (7 ) — Loss from assets held for sale — — 15 15 Depreciation and amortization 246 172 — 418 Operating income (loss) 527 99 (1 ) 625 Earnings (losses) from equity method investments 6 1 — 7 Interest expense, net of capitalization 125 15 4 144 Income tax expense (benefit) 87 (32 ) 44 99 Adjusted net income 280 115 (23 ) 371 Capital expenditures 522 229 — 751 As of December 31, 2018 Property, plant and equipment 14,754 8,697 8 23,459 Equity method investments 142 224 — 366 Total assets $ 22,239 $ 10,703 $ (775 ) $ 32,167 _________________________ (a) Includes Corporate, Gas and intersegment eliminations. Included in revenue-external for the six months ended June 30, 2018 , are: $1,819 million from regulated electric operations, $842 million from regulated gas operations and $(9) million from other operations of Networks; $579 million primarily from renewable energy generation of Renewables. Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three and six months ended June 30, 2019 and 2018 , respectively, is as follows: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 101 $ 128 $ 319 $ 371 Adjustments: Loss from assets held for sale (1) — (10 ) — (15 ) Mark-to-market adjustments - Renewables (2) 20 (3 ) 23 1 Restructuring charges (3) (2 ) — (2 ) (1 ) Accelerated depreciation from repowering (4) (5 ) — (10 ) — Income from release of collateral - Renewables (5) — 7 — 7 Impact of the Tax Act (6) — (7 ) — (7 ) Income tax impact of adjustments (3 ) (7 ) (3 ) (17 ) Gas Storage, net of tax (7) — (2 ) — 11 Net Income Attributable to Avangrid, Inc. $ 110 $ 107 $ 327 $ 351 (1) Represents loss from measurement of assets and liabilities held for sale in connection with the committed plan to sell the gas trading and storage businesses. (2) Mark-to-market adjustments relate to changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity and gas. (3) Restructuring and severance related charges relate to costs resulted from restructuring actions involving initial targeted voluntary workforce reductions and related costs in our plan to vacate a lease, predominantly within the Networks segment and costs to implement an initiative to mitigate costs and achieve sustainable growth. (4) Represents the amount of accelerated depreciation derived from repowering of wind farms in Renewables. (5) Relates to cash collateral released in excess of outstanding receivables from a bankruptcy proceeding with a Renewables customer regarding two power purchase agreements. (6) Represents the impact from measurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. (7) Removal of the impact from Gas activity in the reconciliation to the AVANGRID Net Income. |
Related Party Transactions
Related Party Transactions | 6 Months Ended |
Jun. 30, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, 2019 2018 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ — $ — $ — Iberdrola Renovables Energía, S.L. $ — $ (5 ) $ — $ (4 ) Iberdrola, S.A. $ — $ (10 ) $ — $ (12 ) Other $ 8 $ (1 ) $ — $ — Six Months Ended June 30, 2019 2018 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ — $ — $ (4 ) Iberdrola Renovables Energía, S.L. $ — $ (9 ) $ — $ (7 ) Iberdrola, S.A. $ — $ (20 ) $ — $ (26 ) Iberdrola Energia Monterrey, S.A. de C.V. $ — $ — $ 3 $ — Other $ 8 $ (2 ) $ 1 $ (1 ) In addition to the statements of income items above, we made purchases of turbines for wind farms from Siemens-Gamesa, in which Iberdrola has an 8.1% ownership. The amounts capitalized for these transactions were $2 million and $6 million for the periods ended June 30, 2019 and December 31, 2018 , respectively. Related party balances as of June 30, 2019 and December 31, 2018 , respectively, consisted of: As of June 30, 2019 December 31, 2018 (Millions) Owed By Owed To Owed By Owed To Siemens-Gamesa $ — $ (14 ) $ — $ (14 ) Iberdrola, S.A. $ — $ (20 ) $ 1 $ (40 ) Iberdrola Renovables Energía, S.L. $ 4 $ (12 ) $ 4 $ — Other $ 9 $ (2 ) $ 1 $ (4 ) Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. Transactions with Iberdrola Canada Energy Services (ICES) predominantly relate to the purchase of gas for ARHI’s gas-fired cogeneration facility in Klamath, Oregon. There are no notes payable amounts owed to ICES of as of June 30, 2019 and December 31, 2018 . Transactions with Iberdrola Energia Monterrey predominantly relate to the sale of gas by Enstor Gas for the power generation plant in Monterrey, Mexico. There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances. Networks holds an approximate 20% ownership interest in the regulated New York TransCo, LLC (New York TransCo). Through New York TransCo, Networks has formed a partnership with Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, which is a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York. On April 8, 2019, New York Transco was selected as the developer for Segment B of the AC Transmission Public Policy Project by the NYISO. The selected project, New York Energy Solution (NYES), replaces nearly 80-year old transmission assets located in the upper to mid-Hudson Valley with streamlined, modernized technology, to enable surplus clean energy resources in upstate New York and help achieve the State’s energy goals. The total project cost is $600 million . NYSEG’s contribution as 20% co-owner is $120 million . As of both June 30, 2019 and December 31, 2018 , the amount receivable from New York TransCo was $1 million . We hold a 50% ownership in Vineyard Wind, LLC (Vineyard Wind), a joint venture with Copenhagen Infrastructure Partners. Vineyard Wind acquired an easement from the U.S. Bureau of Ocean Energy Management containing rights to develop offshore wind generation in a 260 square mile area located southeast of Martha’s Vineyard. The area subject to easement has the capacity for siting up to approximately 3,000 MW. In May 2018, Vineyard Wind was selected by the Massachusetts Electric Distribution Companies (EDCs) to construct and operate Vineyard Wind’s proposed 800 MW wind farm and electricity transmission project pursuant to the Massachusetts Green Communities Act Section 83C RFP for offshore wind energy projects. Under the provisions of the LLC agreement, Renewables has contributed $89 million to Vineyard Wind. We expect to provide additional capital contributions. The amount receivable from Vineyard was $7 million and $0 as of June 30, 2019 and December 31, 2018 , respectively. Renewables, through its joint venture in Vineyard Wind, was awarded a second Massachusetts offshore easement. In February 2019, a contribution was made to a new offshore development project of $100 million to enter into the easement contract. AVANGRID manages its overall liquidity position as part of the Iberdrola Group and is a party to a liquidity agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the liquidity agreement. The balance at both June 30, 2019 and December 31, 2018 , was zero . AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023 . AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of June 30, 2019 and December 31, 2018 , there was no outstanding amount under this credit facility. |
Other Financial Statement Items
Other Financial Statement Items | 6 Months Ended |
Jun. 30, 2019 | |
Balance Sheet Related Disclosures [Abstract] | |
Other Financial Statement Items | Other Financial Statement Items Loss from assets held for sale In connection with the sale of our gas trading and storage businesses, we recorded a loss from held for sale measurement of $10 million and $15 million , respectively, for the three and six months ended June 30, 2018 , which is included in “Loss from assets held for sale” in our condensed consolidated statements of income. Accounts receivable Accounts receivable include amounts due under deferred payment arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period of time, which generally exceeds one year, by negotiating mutually acceptable payment terms and not bearing interest. The utility company generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as current. We establish provisions for uncollectible accounts for DPAs by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collection efforts have been exhausted. DPA receivable balances were $69 million and $62 million at June 30, 2019 and December 31, 2018 , respectively. The allowance for doubtful accounts for DPAs at June 30, 2019 and December 31, 2018 , was $34 million and $32 million , respectively. Furthermore, the provision for bad debts associated with the DPAs for the three and six months ended June 30, 2019 and 2018 was $1 million and $2 million , respectively. Prepayments and other current assets Included in prepayments and other current assets are $84 million and $137 million of prepaid other taxes as of June 30, 2019 and December 31, 2018 , respectively. Property, plant and equipment and intangible assets The accumulated depreciation and amortization as of June 30, 2019 and December 31, 2018 , respectively, were as follows: June 30, December 31, As of 2019 2018 (Millions) Property, plant and equipment Accumulated depreciation $ 8,692 $ 8,359 Intangible assets Accumulated amortization $ 298 $ 291 |
Income Tax Expense
Income Tax Expense | 6 Months Ended |
Jun. 30, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Tax Expense | Income Tax Expense The effective tax rates, inclusive of federal and state income tax, for the three and six months ended June 30, 2019 , were 21.6% and 17.9% , respectively. The effective tax rate for the three months ended June 30, 2019 is higher than the federal statutory tax rate of 21% primarily due to unfavorable discrete income tax adjustments recorded in the period, partially offset by production tax credits associated with wind production. The effective tax rate for the six months ended June 30, 2019 is below the federal statutory tax rate of 21% primarily due to the recognition of production tax credits associated with wind production. The effective tax rates, inclusive of federal and state income tax, for the three and six months ended June 30, 2018 , were 19.7% and 22.1% , respectively. The effective tax rate for the three months ended June 30, 2018 is below the federal statutory tax rate of 21% , primarily due to discrete tax adjustments recorded during the period, offset by the recognition of production tax credits associated with wind production. The effective tax rate for the six months ended June 30, 2018 is higher than the federal statutory tax rate of 21% primarily due to the recognition of additional income tax expense of $21.6 million resulting from the disposal of the Gas business, in addition to other discrete tax adjustments recorded during the period, which were partially offset by the recognition of production tax credits associated with wind production. |
Stock-Based Compensation Expens
Stock-Based Compensation Expense | 6 Months Ended |
Jun. 30, 2019 | |
Share-based Payment Arrangement [Abstract] | |
Stock-Based Compensation Expense | Stock-Based Compensation Expense Pursuant to the 2016 Avangrid, Inc. Omnibus Incentive Plan, 3,881 additional performance stock units (PSUs) were granted to certain officers and employees of AVANGRID in March and June 2019. The PSUs will vest upon achievement of certain performance- and market-based metrics related to the 2016 through 2019 plan and will be payable in three equal installments in 2020 , 2021 and 2022 . The fair value on the grant date was determined based on $31.80 per share. The total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three and six months ended June 30, 2019 was $1 million and $2 million , respectively, and for the three and six months ended June 30, 2018 was $0.5 million and $0.4 million , respectively. |
Variable Interest Entities
Variable Interest Entities | 6 Months Ended |
Jun. 30, 2019 | |
Variable Interest Entities [Abstract] | |
Variable Interest Entities | Variable Interest Entities We participate in certain partnership arrangements that qualify as variable interest entities (VIEs). These arrangements consist of tax equity financing arrangements (TEFs) and partnerships in which an investor holds a noncontrolling interest and does not have substantive kick-out or participating rights. The sale of a membership interest in the TEFs represents the sale of an equity interest in a structure that is considered a sale of non-financial assets. Under the sale of non-financial assets, the membership interests in the TEFs we sell to third-party investors are reflected as noncontrolling interest on our condensed consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our condensed consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs. On June 28, 2019, we acquired Patriot Wind Farm LLC and associated entities (Patriot) which have constructed a 226 MW wind farm in Nueces County, Texas for a total purchase price of $320 million . The wind farm constitutes substantially all of the value of the consideration paid to the seller; therefore, the purchase was accounted for as an asset acquisition. We allocated the purchase price to property, plant and equipment of $348 million , derivative liabilities of $26 million and other liabilities of $2 million . In conjunction with the purchase, we entered into a TEF with a third-party investor at a sale price of $128 million . The assets and liabilities of the VIEs totaled approximately $1,178 million and $60 million , respectively, at June 30, 2019 . As of December 31, 2018 , the assets and liabilities of VIEs totaled approximately $876 million and $50 million , respectively. At June 30, 2019 and December 31, 2018 , the assets and liabilities of the VIEs consisted primarily of property, plant and equipment and equity method investments. At June 30, 2019 and December 31, 2018 , equity method investments of VIEs were approximately $98 million and $101 million , respectively. At June 30, 2019 , we consider Aeolus Wind Power II LLC, El Cabo and Patriot to be VIEs. Wind power generation is subject to certain favorable tax treatments in the U.S. In order to monetize the tax benefits, we have entered into these structured institutional partnership investment transactions related to certain wind farms. Under these structures, we contribute certain wind assets, relating both to existing wind farms and wind farms that are being placed into operation at the time of the relevant transaction, and other parties invest in the share equity of the limited liability holding company. As consideration for their investment, the third parties make either an upfront cash payment or a combination of upfront cash and payments over time. We retain a class of membership interest and day-to-day operational and management control, subject to investor approval of certain major decisions. The third-party investors do not receive a lien on any assets and have no recourse against us for their upfront cash payments. The partnerships generally involve disproportionate allocations of profit or loss, cash distributions and tax benefits resulting from the wind farm energy generation between the investor and sponsor until the investor recovers its investment and achieves a cumulative annual after-tax return. Once this target return is met, the relative sharing of profit or loss, cash distributions and taxable income or loss between the Company and the third party investor flips, with the sponsor generally receiving higher percentages thereafter. We also have a call option to acquire the third party investors’ membership interest within a defined time period after this target return is met. Our Aeolus, El Cabo and Patriot interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities associated with the interests. |
Restructuring and Severance Rel
Restructuring and Severance Related Expenses | 6 Months Ended |
Jun. 30, 2019 | |
Restructuring and Related Activities [Abstract] | |
Restructuring and Severance Related Expenses | Restructuring and Severance Related Expenses In 2017, we announced initial targeted voluntary workforce reductions predominantly within the Networks segment. Those actions primarily include: reducing our workforce through voluntary programs in various areas to better align our people resources with business demands and priorities; reorganizing our human resources function to substantially consolidate in Connecticut, as well as related costs to vacate a lease and relocate employees; and reducing our information technology (IT) workforce to make increasing use of external services for operations, support and development of systems. In 2019, we also announced changes across the Company aimed to mitigate costs and deliver sustainable growth, including among others, outsourcing and insourcing of certain areas of the Company and technology initiatives that help improve efficiency and reduce costs. Those decisions and transactions resulted in restructuring charges of $2 million recorded for both the three and six months ended June 30, 2019 , and restructuring charges of $0 and $1 million recorded for the three and six months ended June 30, 2018 , respectively, which are included in "Operations and maintenance" in our condensed consolidated statements of income. The remaining costs for severance agreements are being accrued ratably over the remaining service periods, which span intermittent periods through December 2019. As of June 30, 2019 , our severance and lease restructuring charges reserves, which are recorded in "Other current liabilities" and "Other liabilities" on our condensed consolidated balance sheets, consisted of: Six Months Ended June 30, 2019 (Millions) Beginning Balance $ 4 Restructuring and severance related expenses 2 Payments (2 ) Ending Balance $ 4 |
Subsequent Events
Subsequent Events | 6 Months Ended |
Jun. 30, 2019 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Event On July 16, 2019, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on October 1, 2019 to shareholders of record at the close of business on September 6, 2019. |
Significant Accounting Polici_2
Significant Accounting Policies and New Accounting Pronouncements (Policies) | 6 Months Ended |
Jun. 30, 2019 | |
Accounting Policies [Abstract] | |
New Accounting Pronouncements | Adoption of New Accounting Pronouncements (a) Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC) Topic 842, Leases , with subsequent amendments issued in 2018. The new leases guidance affects all companies and organizations that lease assets, and requires them to record on their balance sheet ROU assets and lease liabilities for the rights and obligations created by those leases. Under ASC 842, a lease is an arrangement that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The new guidance retains a distinction between finance leases and operating leases, while requiring companies to recognize both types of leases on their balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the criteria for distinguishing between capital leases and operating leases in legacy U.S. GAAP - ASC 840. Lessor accounting remains substantially the same as ASC 840, but with some targeted improvements to align lessor accounting with the lessee accounting model and with the revised revenue recognition guidance under ASC 606. The new standard and amendments require new qualitative and quantitative disclosures for both lessees and lessors. We adopted ASC 842 effective January 1, 2019, and elected the optional transition method under which we initially applied the standard on that date without adjusting amounts for prior periods, which we continue to present in accordance with ASC 840, including related disclosures. We recorded the cumulative effect of applying the new leases guidance as an adjustment to beginning retained earnings. In connection with our adoption, we: • did not elect the package of three practical expedients available under the transition provisions which would have allowed us to not reassess: (i) whether expired or existing contracts were or contained leases, (ii) the lease classification for expired or existing leases, and (iii) whether previously capitalized initial direct costs for existing leases would qualify for capitalization under ASC 842. • elected the land easement practical expedient and did not reassess land easements that did not meet the definition of a lease prior to adoption. • used hindsight for determining the lease term and assessing the likelihood that a lease purchase option will be exercised in applying the new leases guidance. • did not separate lease and associated non-lease components for transitioned leases, but instead are accounting for them together as a single lease component. In March 2019, the FASB issued additional amendments to ASC 842 for minor codification improvements, which we early applied effective January 1, 2019, with no material effect to our condensed consolidated results of operations, financial position and cash flows. The cumulative effects of the changes to our condensed consolidated balance sheet as of January 1, 2019, were as follows: Balance at December 31, 2018 Adjustments Due to ASC 842 Balance at January 1, 2019 (Millions) Assets Total Property, Plant and Equipment $ 23,459 $ (147 ) $ 23,312 Operating lease right-of-use assets — 82 82 Other assets 162 146 308 Liabilities Current portion of debt $ 394 $ (28 ) $ 366 Operating lease liabilities, current — 8 8 Other current liabilities 327 28 355 Operating lease liabilities, long-term — 74 74 Other non-current liabilities 499 61 560 Non-current debt 5,368 (61 ) 5,307 Equity Retained earnings $ 1,528 $ (1 ) $ 1,527 Our adoption did not change the classification of lease-related expenses in our condensed consolidated statements of income, and we do not expect significant changes to our pattern of expense recognition. Certain contracts previously classified as lessor leases, consisting mainly of Renewables’ power purchase agreements, no longer meet the definition of a lease under ASC 842. As such, these contracts are accounted for under other U.S. GAAP, but there were no changes to our pattern of revenue recognition. As a result, we expect our adoption will not materially affect our cash flows. In comparison to our operating leases obligations disclosed as of December 31, 2018, certain land easement contracts that previously met the definition of a lease do not meet the ASC 842 definition of a lease, and therefore we excluded them from the transition adjustment. Our accounting for finance (formerly capital) leases is substantially unchanged. Refer to Note 8 for further details. (b) Targeted improvements to accounting for hedging activities In August 2017, the FASB issued targeted amendments with the objective to better align hedge accounting with an entity’s risk management activities in the financial statements, and to simplify the application of hedge accounting. The amendments address concerns of financial statement preparers over difficulties with applying hedge accounting and limitations for hedging both nonfinancial and financial risks and concerns of financial statement users over how hedging activities are reported in financial statements. The amended presentation and disclosure guidance is required only prospectively. Changes to the hedge accounting guidance to address those concerns: 1) expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with an entity’s risk management activities; 2) eliminate the separate measurement and reporting of hedge ineffectiveness, to reduce the complexity of preparing and understanding hedge results; 3) enhance disclosures and change the presentation of hedge results to align the effects of the hedging instrument and the hedged item in order to enhance transparency, comparability and understandability of hedge results; and 4) simplify the way assessments of hedge effectiveness may be performed to reduce the cost and complexity of applying hedge accounting. The amendments ease the administrative burden of hedge documentation requirements and assessing hedge effectiveness going forward. We adopted the hedge accounting amendments on January 1, 2019, and had no cumulative-effect adjustment to retained earnings because there were no amounts of ineffectiveness recorded for any existing hedges as of that date. Concurrently with the above targeted improvements, we adopted the additional amendments the FASB issued in October 2018 that permit use of the Overnight Index Swap rate based on the Secured Overnight Financing Rate as a U.S. benchmark interest rate for hedge accounting purposes. Use of that rate is in addition to the already eligible benchmark interest rates, which are: interest rates on direct Treasury obligations of the U.S. government, the London Interbank Offered Rate swap rate, the OIS Rate based on the Fed Funds Effective Rate and the Securities Industry and Financial Markets Association Municipal Swap Rate. (c) Reclassification of certain tax effects from accumulated other comprehensive income In February 2018, the FASB issued amendments to address a financial reporting issue that arose as a consequence of the Tax Cuts and Jobs Act of 2017 (the Tax Act) that the U.S. federal government enacted on December 22, 2017. Under previous guidance, an entity was required to include the adjustment of deferred taxes for the effect of a change in tax laws or rates in income from continuing operations, thus the associated tax effects of items within AOCI (referred to as stranded tax effects) did not reflect the appropriate tax rate. The amendments allow a reclassification from AOCI to retained earnings to eliminate the stranded tax effects resulting from the Tax Act. The amendments only relate to the reclassification of the income tax effects of the Tax Act, and do not affect the underlying guidance that requires the effect of a change in tax laws or rates to be included in income from continuing operations. We adopted the amendments effective January 1, 2019, and elected to reclassify the stranded tax effects of the Tax Act from AOCI to retained earnings at the beginning of the period of adoption. As a result, we reclassified approximately $12 million from AOCI to retained earnings within our condensed consolidated statements of changes in equity. Accounting Pronouncements Issued But Not Yet Adopted |
Significant Accounting Polici_3
Significant Accounting Policies and New Accounting Pronouncements (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Accounting Policies [Abstract] | |
Schedule of New Accounting Pronouncements | The cumulative effects of the changes to our condensed consolidated balance sheet as of January 1, 2019, were as follows: Balance at December 31, 2018 Adjustments Due to ASC 842 Balance at January 1, 2019 (Millions) Assets Total Property, Plant and Equipment $ 23,459 $ (147 ) $ 23,312 Operating lease right-of-use assets — 82 82 Other assets 162 146 308 Liabilities Current portion of debt $ 394 $ (28 ) $ 366 Operating lease liabilities, current — 8 8 Other current liabilities 327 28 355 Operating lease liabilities, long-term — 74 74 Other non-current liabilities 499 61 560 Non-current debt 5,368 (61 ) 5,307 Equity Retained earnings $ 1,528 $ (1 ) $ 1,527 |
Revenue (Tables)
Revenue (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of Revenues Disaggregated by Major Source for Reportable Segments | Revenues disaggregated by major source for our reportable segments for the three and six months ended June 30, 2019 and 2018 are as follows: Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 802 $ — $ — $ 802 $ 1,715 $ — $ — $ 1,715 Regulated operations – natural gas 249 — — 249 874 — — 874 Nonregulated operations – wind — 221 — 221 — 403 — 403 Nonregulated operations – solar — 8 — 8 — 13 — 13 Nonregulated operations – thermal — — — — — 16 — 16 Other(a) 18 24 — 42 55 17 (4 ) 68 Revenue from contracts with customers 1,069 253 — 1,322 2,644 449 (4 ) 3,089 Leasing revenue 3 — — 3 4 — — 4 Derivative revenue — 48 — 48 — 89 — 89 Alternative revenue programs 19 — — 19 35 — — 35 Other revenue 2 6 — 8 14 11 — 25 Total operating revenues $ 1,093 $ 307 $ — $ 1,400 $ 2,697 $ 549 $ (4 ) $ 3,242 Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 800 $ — $ — $ 800 $ 1,726 $ — $ — $ 1,726 Regulated operations – natural gas 266 — — 266 838 — — 838 Nonregulated operations – wind — 180 — 180 — 348 — 348 Nonregulated operations – solar — 6 — 6 — 8 — 8 Nonregulated operations – thermal — 1 — 1 — 14 — 14 Nonregulated operations – gas storage — — 6 6 — — 10 10 Other(a) 6 (10 ) (6 ) (10 ) 31 (33 ) 9 7 Revenue from contracts with customers 1,072 177 — 1,249 2,595 337 19 2,951 Leasing revenue 9 98 — 107 18 179 — 197 Derivative revenue — 22 — 22 — 65 10 75 Alternative revenue programs 25 — — 25 44 — — 44 Other revenue (1 ) — — (1 ) — — — — Total operating revenues $ 1,105 $ 297 $ — $ 1,402 $ 2,657 $ 581 $ 29 $ 3,267 (a) Primarily includes certain intra-month trading activities, billing, collection, and administrative charges, sundry billings, and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate, Gas and intersegment eliminations. |
Schedule of Aggregate Transaction Price Allocations | As of June 30, 2019 , the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of June 30, 2019 2020 2021 2022 2023 2024 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ 1 $ 1 $ 1 $ 1 $ — $ 5 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 15 13 9 3 1 — 41 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 18 13 8 5 4 9 57 Total operating revenues $ 34 $ 27 $ 18 $ 9 $ 6 $ 9 $ 103 |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Regulated Operations [Abstract] | |
Schedule of Delivery Rate Increases | The below table provides a summary of the proposed delivery rate increases, delivery revenue percentages and total revenue percentages for all four businesses: Requested Revenue Increase Delivery Revenue Total Revenue Utility (Millions) % % NYSEG Electric $ 156.7 20.4 % 10.4 % NYSEG Gas $ 6.3 3.0 % 1.4 % RG&E Electric $ 31.7 7.0 % 4.1 % RG&E Gas $ 5.8 3.3 % 1.4 % |
Schedule of Current and Non-Current Regulatory Assets | Regulatory assets as of June 30, 2019 and December 31, 2018 , respectively, consisted of: June 30, December 31, As of 2019 2018 (Millions) Pension and other post-retirement benefits cost deferrals $ 135 $ 141 Pension and other post-retirement benefits 1,083 1,138 Storm costs 342 346 Rate adjustment mechanism 16 18 Reliability support services 2 13 Revenue decoupling mechanism 10 7 Transmission revenue reconciliation mechanism 5 11 Contracts for differences 97 97 Hardship programs 26 26 Plant decommissioning 8 11 Deferred purchased gas 1 37 Deferred transmission expense 2 11 Environmental remediation costs 286 278 Debt premium 102 118 Unamortized losses on reacquired debt 23 23 Unfunded future income taxes 365 371 Federal tax depreciation normalization adjustment 155 157 Asset retirement obligation 18 18 Deferred meter replacement costs 28 29 Other 97 95 Total regulatory assets 2,801 2,945 Less: current portion 247 299 Total non-current regulatory assets $ 2,554 $ 2,646 |
Schedule of Current and Non-Current Regulatory Liabilities | Regulatory liabilities as of June 30, 2019 and December 31, 2018 , respectively, consisted of: June 30, December 31, As of 2019 2018 (Millions) Energy efficiency portfolio standard $ 73 $ 56 Gas supply charge and deferred natural gas cost 17 4 Pension and other post-retirement benefits cost deferrals 98 97 Carrying costs on deferred income tax bonus depreciation 60 72 Carrying costs on deferred income tax - Mixed Services 263(a) 18 20 2017 Tax Act 1,547 1,509 Revenue decoupling mechanism 21 19 Accrued removal obligations 1,169 1,153 Asset sale gain account 10 10 Economic development 29 28 Positive benefit adjustment 38 39 Theoretical reserve flow thru impact 16 19 Deferred property tax 41 25 Net plant reconciliation 22 19 Debt rate reconciliation 58 49 Rate refund – FERC ROE proceeding 30 29 Transmission congestion contracts 23 21 Merger-related rate credits 17 18 Accumulated deferred investment tax credits 14 14 Asset retirement obligation 13 13 Earning sharing provisions 18 17 Middletown/Norwalk local transmission network service collections 20 19 Low income programs 35 38 Non-firm margin sharing credits 16 10 Other 139 129 Total regulatory liabilities 3,542 3,428 Less: current portion 256 205 Total non-current regulatory liabilities $ 3,286 $ 3,223 |
Fair Value of Financial Instr_2
Fair Value of Financial Instruments and Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value Measurements | The financial instruments measured at fair value as of June 30, 2019 and December 31, 2018 , respectively, consisted of: As of June 30, 2019 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 35 $ — $ — $ — $ 35 Derivative assets Derivative financial instruments - power 10 27 123 (72 ) 88 Derivative financial instruments - gas — 20 37 (57 ) — Contracts for differences — — 2 — 2 Derivative financial instruments – other — 1 — — 1 Total 10 48 162 (129 ) 91 Derivative liabilities Derivative financial instruments - power (17 ) (49 ) (86 ) 111 (41 ) Derivative financial instruments - gas (3 ) (21 ) (8 ) 27 (5 ) Contracts for differences — — (99 ) — (99 ) Derivative financial instruments – other — (1 ) (1 ) — (2 ) Total $ (20 ) $ (71 ) $ (194 ) $ 138 $ (147 ) As of December 31, 2018 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 37 $ — $ — $ — $ 37 Derivative assets Derivative financial instruments - power 17 23 91 (59 ) 72 Derivative financial instruments - gas 1 20 36 (55 ) 2 Contracts for differences — — 5 — 5 Total 18 43 132 (114 ) 79 Derivative liabilities Derivative financial instruments - power (12 ) (41 ) (36 ) 77 (12 ) Derivative financial instruments - gas (1 ) (23 ) (7 ) 22 (9 ) Contracts for differences — — (102 ) — (102 ) Derivative financial instruments - other — (16 ) (2 ) — (18 ) Total $ (13 ) $ (80 ) $ (147 ) $ 99 $ (141 ) |
Fair Value, Financial instrument Based on Level 3 Reconciliation | Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input June 30, 2019 Risk of non-performance 0.14% - 0.54% Discount rate 1.76% - 1.87% Forward pricing ($ per KW-month) $3.80 - $7.03 The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and six months ended June 30, 2019 and 2018 , respectively, is as follows: Three Months Ended June 30, Six Months Ended June 30, (Millions) 2019 2018 2019 2018 Fair Value Beginning of Period, $ (22 ) $ (9 ) $ (15 ) $ 6 Gains recognized in operating revenues 14 9 37 14 (Losses) recognized in operating revenues — (2 ) (11 ) (6 ) Total gains recognized in operating revenues 14 7 26 8 Gains recognized in OCI 1 2 — — (Losses) recognized in OCI — — (13 ) — Total gains recognized in OCI 1 2 (13 ) — Net change recognized in regulatory assets and liabilities 2 3 — (8 ) Purchases (26 ) (1 ) (26 ) (3 ) Settlements (1 ) (3 ) (4 ) (4 ) Fair Value as of June 30, $ (32 ) $ (1 ) $ (32 ) $ (1 ) Gains for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ 14 $ 7 $ 26 $ 8 |
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques | The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives. As of June 30, 2019 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps with delivery period > two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 2.92 $ 4.90 $ 2.14 Indiana hub ($/MWh) $ 30.66 $ 61.12 $ 19.10 Mid C ($/MWh) $ 24.86 $ 105.00 $ (0.50 ) Minn hub ($/MWh) $ 25.22 $ 52.17 $ 12.51 NoIL hub ($/MWh) $ 27.46 $ 55.39 $ 15.50 |
Derivative Instruments and He_2
Derivative Instruments and Hedging (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Condensed Consolidated Balance Sheet and Amounts | The tables below present Renewables' derivative positions as of June 30, 2019 and December 31, 2018 , respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets: As of June 30, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 23 $ 121 $ 41 $ 9 Derivative liabilities (2 ) (8 ) (58 ) (32 ) 21 113 (17 ) (23 ) Designated as hedging instruments Derivative assets — 1 3 9 Derivative liabilities — (5 ) (10 ) (49 ) — (4 ) (7 ) (40 ) Total derivatives before offset of cash collateral 21 109 (24 ) (63 ) Cash collateral receivable (payable) (10 ) (32 ) 11 30 Total derivatives as presented in the balance sheet $ 11 $ 77 $ (13 ) $ (33 ) As of December 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 19 $ 96 $ 29 $ 17 Derivative liabilities (5 ) (3 ) (48 ) (35 ) 14 93 (19 ) (18 ) Designated as hedging instruments Derivative assets 2 1 2 4 Derivative liabilities — — (7 ) (10 ) 2 1 (5 ) (6 ) Total derivatives before offset of cash collateral 16 94 (24 ) (24 ) Cash collateral receivable (payable) (8 ) (34 ) 9 17 Total derivatives as presented in the balance sheet $ 8 $ 60 $ (15 ) $ (7 ) The tables below present Networks' derivative positions as of June 30, 2019 and December 31, 2018 , respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets: As of June 30, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 8 $ 4 $ 8 $ 2 Derivative liabilities (8 ) (2 ) (24 ) (95 ) — 2 (16 ) (93 ) Designated as hedging instruments Derivative assets 1 — — — Derivative liabilities — — (1 ) — 1 — (1 ) — Total derivatives before offset of cash collateral 1 2 (17 ) (93 ) Cash collateral receivable — — 6 4 Total derivatives as presented in the balance sheet $ 1 $ 2 $ (11 ) $ (89 ) As of December 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 18 $ 6 $ 10 $ 3 Derivative liabilities (10 ) (3 ) (21 ) (93 ) 8 3 (11 ) (90 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (2 ) — — — (2 ) — Total derivatives before offset of cash collateral 8 3 (13 ) (90 ) Cash collateral receivable — — — — Total derivatives as presented in the balance sheet $ 8 $ 3 $ (13 ) $ (90 ) |
Schedule of Notional Volumes of Outstanding Derivative Positions | The net notional volumes of outstanding derivative instruments associated with Renewables activities as of June 30, 2019 and December 31, 2018 , respectively, consisted of: June 30, December 31, As of 2019 2018 (MWh/Dth in millions) Wholesale electricity purchase contracts 5 5 Wholesale electricity sales contracts 12 6 Natural gas and other fuel purchase contracts 35 29 Financial power contracts 11 11 Basis swaps – purchases 46 42 Basis swaps – sales 1 4 The net notional volumes of the outstanding derivative instruments associated with Networks activities as of June 30, 2019 and December 31, 2018 , respectively, consisted of: June 30, December 31, As of 2019 2018 (Millions) Wholesale electricity purchase contracts (MWh) 4.5 4.9 Natural gas purchase contracts (Dth) 7.0 7.8 Fleet fuel purchase contracts (Gallons) 2.1 2.1 |
Summary of Unrealized Gains and Losses from Fair Value Adjustments | The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of June 30, 2019 and December 31, 2018 and amounts reclassified from regulatory assets and liabilities into income for the three and six months ended June 30, 2019 and 2018 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of Three Months Ended June 30, Six Months Ended June 30, June 30, 2019 Electricity Natural Gas 2019 Electricity Natural Gas Electricity Natural Gas Regulatory assets $ 7 $ 3 Purchased power, natural gas and fuel used $ 6 $ — $ 10 $ — December 31, 2018 2018 Regulatory assets $ — $ — Purchased power, natural gas and fuel used $ 1 $ — $ (5 ) $ 2 Regulatory liabilities $ 5 $ — The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three and six months ended June 30, 2019 and 2018 , respectively, were as follows: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (Millions) Derivative assets $ (2 ) $ (2 ) $ (3 ) $ (4 ) Derivative liabilities $ 4 $ 6 $ 3 $ (3 ) |
Schedule of Derivative Instruments, Effect of Cash flow Hedging on Other Comprehensive Income and Income | The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, (Loss) Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Interest rate contracts $ — Interest expense $ 2 $ 76 Commodity contracts (1 ) Purchased power, natural gas and fuel used — 259 Foreign currency exchange contracts 1 — Total $ — $ 2 2018 Interest rate contracts $ — Interest expense $ 2 $ 70 Commodity contracts — Purchased power, natural gas and fuel used — 279 Total $ — $ 2 Six Months Ended June 30, Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Interest rate contracts $ — Interest expense $ 4 $ 154 Commodity contracts — Purchased power, natural gas and fuel used — 822 Foreign currency exchange contracts 1 — Total $ 1 $ 4 2018 Interest rate contracts $ — Interest expense $ 4 $ 144 Commodity contracts — Purchased power, natural gas and fuel used — 855 Total $ — $ 4 (a) Changes in accumulated OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, Gain Recognized in OCI on Derivatives (a) Location of (Gain) Reclassified from Accumulated OCI into Income (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Commodity contracts $ 5 Operating revenues $ — $ 1,400 2018 Commodity contracts $ — Operating revenues $ (1 ) $ 1,402 Six Months Ended June 30, (Loss) Recognized in OCI on Derivatives (a) Location of (Gain) Reclassified from Accumulated OCI into Income (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Commodity contracts $ (15 ) Operating revenues $ — $ 3,242 2018 Commodity contracts $ (1 ) Operating revenues $ (20 ) $ 3,267 (a) Changes in OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, Loss Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Interest rate contracts $ (4 ) Interest expense $ — $ 76 2018 Interest rate contracts $ (4 ) Interest expense $ — $ 70 Six Months Ended June 30, Loss Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Interest rate contracts $ (24 ) Interest expense $ — $ 154 2018 Interest rate contracts $ (4 ) Interest expense $ — $ 144 (a) Changes in OCI are reported on a pre-tax basis. The amount in accumulated OCI is being reclassified into earnings over the underlying debt maturity period which ends in 2029. |
Schedule of Fair Value, Net Derivative Contracts | The fair values of derivative contracts associated with Renewables activities as of June 30, 2019 and December 31, 2018 , respectively, consisted of: June 30, December 31, As of 2019 2018 (Millions) Wholesale electricity purchase contracts $ 28 $ 11 Wholesale electricity sales contracts (52 ) (12 ) Natural gas and other fuel purchase contracts (3 ) (2 ) Financial power contracts 71 55 Basis swaps – purchases (2 ) (6 ) Total $ 42 $ 46 |
Effect of Derivatives Associated with Renewables and Gas Activities | The effects of trading and non-trading derivatives associated with Renewables activities for the three and six months ended June 30, 2019 , consisted of: Three Months Ended Six Months Ended June 30, 2019 June 30, 2019 Trading Non-trading Total amount per income statement Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (2 ) $ — $ (1 ) $ — Wholesale electricity sales contracts 2 4 2 (5 ) Financial power contracts 1 22 — 9 Financial and natural gas contracts — 2 (1 ) — Total gain included in operating revenues $ 1 $ 28 $ 1,400 $ — $ 4 $ 3,242 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (3 ) $ — $ 17 Wholesale electricity sales contracts — — — — Financial power contracts — (3 ) — (2 ) Financial and natural gas contracts — (3 ) — 4 Total (loss) gain included in purchased power, natural gas and fuel used $ — $ (9 ) $ 259 $ — $ 19 $ 822 Total Gain $ 1 $ 19 $ — $ 23 The effects of trading and non-trading derivatives associated with Renewables activities for the three and six months ended June 30, 2018 , consisted of: Three Months Ended Six Months Ended June 30, 2018 June 30, 2018 (Millions) Trading Non-trading Trading Non-trading Wholesale electricity purchase contracts $ 5 $ 3 $ 6 $ 4 Wholesale electricity sales contracts (2 ) (7 ) (1 ) (7 ) Financial power contracts (1 ) (2 ) (2 ) 1 Financial and natural gas contracts — (1 ) 3 4 Total Gain (Loss) $ 2 $ (7 ) $ 6 $ 2 |
Derivative Liabilities | The table below presents our interest rate swap derivative positions as of June 30, 2019 and December 31, 2018 , respectively, including the location of the net derivative positions on our condensed consolidated balance sheets: As of June 30, 2019 Current Liabilities (Millions) Designated as hedging instruments Derivative liabilities $ — As of December 31, 2018 Designated as hedging instruments Derivative liabilities $ (16 ) |
Leases (Tables)
Leases (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Leases [Abstract] | |
Lease, Cost | For the six months ended June 30, 2019 , supplemental cash flow information related to leases was as follows: Six Months Ended June 30, 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 6 Operating cash flows from finance leases $ 2 Financing cash flows from finance leases $ 25 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ — Operating leases $ (1 ) The components of lease cost and other information related to leases as of and for the three and six months ended June 30, 2019 were as follows: Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 3 $ 6 Interest on lease liabilities 1 2 Total finance lease cost 4 8 Operating lease cost 3 8 Short-term lease cost 1 2 Variable lease cost 1 1 Total lease cost $ 9 $ 19 |
Assets And Liabilities, Lessee | As of June 30, 2019 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 77 Operating lease liabilities, current 11 Operating lease liabilities, long-term 69 Total operating lease liabilities $ 80 Finance Leases Other assets $ 139 Other current liabilities 8 Other non-current liabilities 55 Total finance lease liabilities $ 63 Weighted-average Remaining Lease Term (years): Finance leases 8.01 Operating leases 13.08 Weighted-average Discount Rate: Finance leases 5.50 % Operating leases 3.68 % |
Operating Lease Maturity | As of June 30, 2019 , maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, July 1, 2019 - December 31, 2019 $ 3 $ 7 2020 10 14 2021 6 13 2022 2 10 2023 50 8 Thereafter 4 56 Total lease payments 75 108 Less: imputed interest (12 ) (28 ) Total $ 63 $ 80 |
Finance Lease Maturity | As of June 30, 2019 , maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, July 1, 2019 - December 31, 2019 $ 3 $ 7 2020 10 14 2021 6 13 2022 2 10 2023 50 8 Thereafter 4 56 Total lease payments 75 108 Less: imputed interest (12 ) (28 ) Total $ 63 $ 80 |
Future Minimum Payments, Operating Leases | Total future minimum lease payments as of December 31, 2018 consisted of: Year Operating Leases Capital Leases Total (Millions) 2019 $ 31 $ 30 $ 61 2020 39 10 49 2021 38 7 45 2022 35 2 37 2023 33 50 83 Thereafter 735 2 737 Total $ 911 $ 101 $ 1,012 |
Future Minimum Payments, Capital Leases | Total future minimum lease payments as of December 31, 2018 consisted of: Year Operating Leases Capital Leases Total (Millions) 2019 $ 31 $ 30 $ 61 2020 39 10 49 2021 38 7 45 2022 35 2 37 2023 33 50 83 Thereafter 735 2 737 Total $ 911 $ 101 $ 1,012 |
Post-retirement and Similar O_2
Post-retirement and Similar Obligations (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Retirement Benefits [Abstract] | |
Components of Net Periodic Pension and Postretirement Benefits | The components of net periodic benefit cost for pension benefits for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (Millions) Service cost $ 10 $ 11 $ 20 $ 22 Interest cost 32 32 65 64 Expected return on plan assets (48 ) (50 ) (96 ) (100 ) Amortization of: Prior service costs (1 ) 1 (1 ) 1 Actuarial loss 27 37 57 75 Net Periodic Benefit Cost $ 20 $ 31 $ 45 $ 62 The components of net periodic benefit cost for postretirement benefits for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (Millions) Service cost $ — $ 1 $ 1 $ 2 Interest cost 4 5 8 9 Expected return on plan assets (2 ) (2 ) (4 ) (4 ) Amortization of: Prior service costs (2 ) (2 ) (4 ) (4 ) Actuarial loss (1 ) 2 (1 ) 3 Net Periodic Benefit Cost $ (1 ) $ 4 $ — $ 6 |
Equity (Tables)
Equity (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Gain (Loss) | Accumulated Other Comprehensive Loss for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: As of March 31, Adoption of Three Months Ended June 30, As of June 30, As of March 31, Adoption of new accounting Three Months Ended June 30, As of June 30, 2019 standard 2019 2019 2018 standard 2018 2018 (Millions) Change in revaluation of defined benefit plans, net of income tax expense of $0.2 for 2018 $ (13 ) $ — $ — $ (13 ) $ (14 ) $ — $ 1 $ (13 ) Loss on nonqualified pension plans (6 ) — (1 ) (7 ) (7 ) — — (7 ) Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $0.5 for 2019 and $(1.5) for 2018 (20 ) — 2 (18 ) 30 — (5 ) 25 Reclassification to net income of losses on cash flow hedges, net of income tax expense of $0.2 for 2019(a) (72 ) — 1 (71 ) (66 ) — — (66 ) Gain (loss) on derivatives qualifying as cash flow hedges (92 ) — 3 (89 ) (36 ) — (5 ) (41 ) Accumulated Other Comprehensive (Loss) Gain $ (111 ) $ — $ 2 $ (109 ) $ (57 ) $ — $ (4 ) $ (61 ) As of December 31, Adoption of new accounting Six Months Ended June 30, As of June 30, As of December 31, Adoption of new accounting Six Months Ended June 30, As of June 30, 2018 standard 2019 2019 2017 standard 2018 2018 (Millions) Change in revaluation of defined benefit plans, net of income tax expense of $0.2 for 2018 $ (11 ) $ (2 ) $ — $ (13 ) $ (14 ) $ — $ 1 $ (13 ) Loss on nonqualified pension plans (6 ) — (1 ) (7 ) (6 ) (1 ) — (7 ) Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(10.4) for 2019 and $(1.5) for 2018 9 — (27 ) (18 ) 30 — (5 ) 25 Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $0.9 for 2019 and $(7.2) for 2018(a) (64 ) (10 ) 3 (71 ) (56 ) — (10 ) (66 ) Loss on derivatives qualifying as cash flow hedges (55 ) (10 ) (24 ) (89 ) (26 ) — (15 ) (41 ) Accumulated Other Comprehensive Loss $ (72 ) $ (12 ) $ (25 ) $ (109 ) $ (46 ) $ (1 ) $ (14 ) $ (61 ) ________________________ (a)Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income. |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share, Basic and Diluted | The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 110 $ 107 $ 327 $ 351 Denominator: Weighted average number of shares outstanding - basic 309,491,082 309,517,854 309,491,082 309,515,758 Weighted average number of shares outstanding - diluted 309,512,752 309,719,584 309,509,620 309,711,682 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.36 $ 0.35 $ 1.06 $ 1.13 Earnings Per Common Share, Diluted $ 0.36 $ 0.34 $ 1.06 $ 1.13 |
Segment Information (Tables)
Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Segment Reporting [Abstract] | |
Schedule of Segment Information | Segment information for the three and six months ended June 30, 2018 , consisted of: Three Months Ended June 30, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,103 $ 296 $ 3 $ 1,402 Revenue - intersegment 2 1 (3 ) — Loss from assets held for sale — — 10 10 Depreciation and amortization 128 87 — 215 Operating income (loss) 183 55 (16 ) 222 Earnings (losses) from equity method investments 4 1 — 5 Interest expense, net of capitalization 65 7 (2 ) 70 Income tax expense (benefit) 23 (24 ) 28 27 Adjusted net income $ 79 $ 68 $ (18 ) $ 128 Included in revenue-external for the three months ended June 30, 2018 , are: $864 million from regulated electric operations, $242 million from regulated gas operations and $(3) million from other operations of Networks; $296 million primarily from renewable energy generation of Renewables. Six Months Ended June 30, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 2,652 $ 579 $ 36 $ 3,267 Revenue - intersegment 5 2 (7 ) — Loss from assets held for sale — — 15 15 Depreciation and amortization 246 172 — 418 Operating income (loss) 527 99 (1 ) 625 Earnings (losses) from equity method investments 6 1 — 7 Interest expense, net of capitalization 125 15 4 144 Income tax expense (benefit) 87 (32 ) 44 99 Adjusted net income 280 115 (23 ) 371 Capital expenditures 522 229 — 751 As of December 31, 2018 Property, plant and equipment 14,754 8,697 8 23,459 Equity method investments 142 224 — 366 Total assets $ 22,239 $ 10,703 $ (775 ) $ 32,167 _________________________ (a) Includes Corporate, Gas and intersegment eliminations. Segment information as of and for the three and six months ended June 30, 2019 , consisted of: Three Months Ended June 30, 2019 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,092 $ 307 $ 1 $ 1,400 Revenue - intersegment 1 — (1 ) — Depreciation and amortization 135 87 — 222 Operating income 155 49 3 207 Earnings (losses) from equity method investments 2 (1 ) — 1 Interest expense, net of capitalization 66 2 7 76 Income tax expense (benefit) 25 (18 ) 22 29 Adjusted net income $ 66 $ 64 $ (29 ) $ 101 Included in revenue-external for the three months ended June 30, 2019 , are: $836 million from regulated electric operations, $254 million from regulated gas operations and $2 million from other operations of Networks; $307 million primarily from renewable energy generation of Renewables. Six Months Ended June 30, 2019 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 2,692 $ 549 $ 1 $ 3,242 Revenue - intersegment 5 — (5 ) — Depreciation and amortization 269 175 — 444 Operating income 486 62 — 548 Earnings (losses) from equity method investments 5 (3 ) — 2 Interest expense, net of capitalization 135 7 12 154 Income tax expense (benefit) 89 (17 ) (2 ) 70 Adjusted net income 267 69 (16 ) 319 Capital expenditures 678 659 — 1,337 As of June 30, 2019 Property, plant and equipment 15,104 9,261 8 24,373 Equity method investments 144 361 — 505 Total assets $ 22,491 $ 11,905 $ (1,255 ) $ 33,141 _________________________ (a) Includes Corporate, Gas and intersegment eliminations. |
Schedule of Reconciliation of Adjusted Net Income to Net Income | Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three and six months ended June 30, 2019 and 2018 , respectively, is as follows: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 101 $ 128 $ 319 $ 371 Adjustments: Loss from assets held for sale (1) — (10 ) — (15 ) Mark-to-market adjustments - Renewables (2) 20 (3 ) 23 1 Restructuring charges (3) (2 ) — (2 ) (1 ) Accelerated depreciation from repowering (4) (5 ) — (10 ) — Income from release of collateral - Renewables (5) — 7 — 7 Impact of the Tax Act (6) — (7 ) — (7 ) Income tax impact of adjustments (3 ) (7 ) (3 ) (17 ) Gas Storage, net of tax (7) — (2 ) — 11 Net Income Attributable to Avangrid, Inc. $ 110 $ 107 $ 327 $ 351 (1) Represents loss from measurement of assets and liabilities held for sale in connection with the committed plan to sell the gas trading and storage businesses. (2) Mark-to-market adjustments relate to changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity and gas. (3) Restructuring and severance related charges relate to costs resulted from restructuring actions involving initial targeted voluntary workforce reductions and related costs in our plan to vacate a lease, predominantly within the Networks segment and costs to implement an initiative to mitigate costs and achieve sustainable growth. (4) Represents the amount of accelerated depreciation derived from repowering of wind farms in Renewables. (5) Relates to cash collateral released in excess of outstanding receivables from a bankruptcy proceeding with a Renewables customer regarding two power purchase agreements. (6) Represents the impact from measurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. (7) Removal of the impact from Gas activity in the reconciliation to the AVANGRID Net Income. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | Related party transactions for the three and six months ended June 30, 2019 and 2018 , respectively, consisted of: Three Months Ended June 30, 2019 2018 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ — $ — $ — Iberdrola Renovables Energía, S.L. $ — $ (5 ) $ — $ (4 ) Iberdrola, S.A. $ — $ (10 ) $ — $ (12 ) Other $ 8 $ (1 ) $ — $ — Six Months Ended June 30, 2019 2018 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ — $ — $ (4 ) Iberdrola Renovables Energía, S.L. $ — $ (9 ) $ — $ (7 ) Iberdrola, S.A. $ — $ (20 ) $ — $ (26 ) Iberdrola Energia Monterrey, S.A. de C.V. $ — $ — $ 3 $ — Other $ 8 $ (2 ) $ 1 $ (1 ) |
Schedule of Related Party Balances | Related party balances as of June 30, 2019 and December 31, 2018 , respectively, consisted of: As of June 30, 2019 December 31, 2018 (Millions) Owed By Owed To Owed By Owed To Siemens-Gamesa $ — $ (14 ) $ — $ (14 ) Iberdrola, S.A. $ — $ (20 ) $ 1 $ (40 ) Iberdrola Renovables Energía, S.L. $ 4 $ (12 ) $ 4 $ — Other $ 9 $ (2 ) $ 1 $ (4 ) |
Other Financial Statement Ite_2
Other Financial Statement Items (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Balance Sheet Related Disclosures [Abstract] | |
Schedule of Accumulated Depreciation and Amortization | The accumulated depreciation and amortization as of June 30, 2019 and December 31, 2018 , respectively, were as follows: June 30, December 31, As of 2019 2018 (Millions) Property, plant and equipment Accumulated depreciation $ 8,692 $ 8,359 Intangible assets Accumulated amortization $ 298 $ 291 |
Restructuring and Severance R_2
Restructuring and Severance Related Expenses (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Restructuring and Related Activities [Abstract] | |
Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities | As of June 30, 2019 , our severance and lease restructuring charges reserves, which are recorded in "Other current liabilities" and "Other liabilities" on our condensed consolidated balance sheets, consisted of: Six Months Ended June 30, 2019 (Millions) Beginning Balance $ 4 Restructuring and severance related expenses 2 Payments (2 ) Ending Balance $ 4 |
Background and Nature Of Oper_2
Background and Nature Of Operations (Detail) | 6 Months Ended |
Jun. 30, 2019 | |
Avangrid | Iberdrola S.A. | |
Nature Of Business [Line Items] | |
Ownership percentage held by parent | 81.50% |
Significant Accounting Polici_4
Significant Accounting Policies and New Accounting Pronouncements - Narrative (Details) $ in Millions | Jan. 01, 2019USD ($) |
Accounting Policies [Abstract] | |
Reclassification from AOCI to retained earnings | $ 12 |
Significant Accounting Polici_5
Significant Accounting Policies and New Accounting Pronouncements - Schedule of Balance Sheet Effects (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Jan. 01, 2019 | Dec. 31, 2018 |
Assets | |||
Property, plant and equipment | $ 24,373 | $ 23,312 | $ 23,459 |
Operating lease right-of-use assets | 77 | 82 | 0 |
Other | 247 | 308 | 162 |
Liabilities | |||
Current portion of debt | 374 | 366 | 394 |
Operating lease liabilities | 11 | 8 | 0 |
Other current liabilities | 291 | 355 | 327 |
Operating lease liabilities | 69 | 74 | 0 |
Other | 527 | 560 | 499 |
Non-current debt | 6,282 | 5,307 | 5,368 |
Equity | |||
Retained earnings | $ 1,594 | 1,527 | $ 1,528 |
Adjustments Due to ASC 842 | |||
Assets | |||
Property, plant and equipment | (147) | ||
Operating lease right-of-use assets | 82 | ||
Other | 146 | ||
Liabilities | |||
Current portion of debt | (28) | ||
Operating lease liabilities | 8 | ||
Other current liabilities | 28 | ||
Operating lease liabilities | 74 | ||
Other | 61 | ||
Non-current debt | (61) | ||
Equity | |||
Retained earnings | $ (1) |
Revenue - Narrative (Detail)
Revenue - Narrative (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Dec. 31, 2018 | |
Utility Revenue [Line Items] | |||||
Contract assets | $ 12 | $ 12 | $ 9 | ||
TCC contract liabilities | 12 | 12 | 9 | ||
Revenue recognized | 4 | $ 4 | 9 | $ 8 | |
Accounts receivable related to contracts with customers | 980 | 980 | 1,118 | ||
Unbilled revenues | 284 | 284 | $ 374 | ||
Revenue, Remaining Performance Obligation, Amount | $ 29 | $ 29 | |||
Networks | |||||
Utility Revenue [Line Items] | |||||
Revenue performance obligation, timing | P1Y | ||||
Renewables | |||||
Utility Revenue [Line Items] | |||||
Capitalized contract cost amortization term | 15 years | ||||
Capitalized contract cost expected life | 10 years | ||||
Transmission congestion contracts | Minimum | |||||
Utility Revenue [Line Items] | |||||
Auction period | 6 months | 6 months | |||
Transmission congestion contracts | Maximum | |||||
Utility Revenue [Line Items] | |||||
Auction period | 2 years | 2 years |
Revenue - Schedule of Revenues
Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Segment Reporting Information [Line Items] | ||||
Operating revenues | $ 1,322 | $ 1,249 | $ 3,089 | $ 2,951 |
Leasing revenue | 3 | 107 | 4 | 197 |
Derivative revenue | 48 | 22 | 89 | 75 |
Alternative revenue programs | 19 | 25 | 35 | 44 |
Other revenue | 8 | (1) | 25 | 0 |
Revenues | 1,400 | 1,402 | 3,242 | 3,267 |
Electricity | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 802 | 800 | 1,715 | 1,726 |
Natural Gas | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 249 | 266 | 874 | 838 |
Wind Energy | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 221 | 180 | 403 | 348 |
Solar Energy | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 8 | 6 | 13 | 8 |
Thermal Energy | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 1 | 16 | 14 | |
Gas Storage | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 6 | 10 | ||
Other | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 42 | (10) | 68 | 7 |
Networks | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 1,069 | 1,072 | 2,644 | 2,595 |
Leasing revenue | 3 | 9 | 4 | 18 |
Alternative revenue programs | 19 | 25 | 35 | 44 |
Other revenue | 2 | (1) | 14 | |
Revenues | 1,093 | 1,105 | 2,697 | 2,657 |
Networks | Electricity | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 802 | 800 | 1,715 | 1,726 |
Revenues | 836 | 864 | 1,800 | 1,819 |
Networks | Natural Gas | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 249 | 266 | 874 | 838 |
Revenues | 254 | 242 | 890 | 842 |
Networks | Other | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 18 | 6 | 55 | 31 |
Renewables | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 253 | 177 | 449 | 337 |
Leasing revenue | 98 | 179 | ||
Derivative revenue | 48 | 22 | 89 | 65 |
Other revenue | 6 | 11 | ||
Revenues | 307 | 297 | 549 | 581 |
Renewables | Wind Energy | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 221 | 180 | 403 | 348 |
Renewables | Solar Energy | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 8 | 6 | 13 | 8 |
Renewables | Thermal Energy | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 1 | 16 | 14 | |
Renewables | Other | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 24 | (10) | 17 | (33) |
Other | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 0 | 0 | (4) | 19 |
Derivative revenue | 10 | |||
Revenues | 0 | 0 | (4) | 29 |
Other | Gas Storage | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 6 | 10 | ||
Other | Other | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | $ 0 | $ (6) | $ (4) | $ 9 |
Revenue - Schedule of Aggregate
Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Detail) $ in Millions | Jun. 30, 2019USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 29 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | 34 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Retail Energy Sales Contracts In Place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 1 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Capacity And Carbon Free Energy Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 15 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Renewable Energy Credit Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 18 |
Remaining performance obligation, 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] | |
Total operating revenues | $ 27 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Retail Energy Sales Contracts In Place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 1 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Capacity And Carbon Free Energy Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 13 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Renewable Energy Credit Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 13 |
Remaining performance obligation, 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] | |
Total operating revenues | $ 18 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Retail Energy Sales Contracts In Place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 1 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Capacity And Carbon Free Energy Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 9 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Renewable Energy Credit Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 8 |
Remaining performance obligation, 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] | |
Total operating revenues | $ 9 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Retail Energy Sales Contracts In Place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 1 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Capacity And Carbon Free Energy Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 3 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Renewable Energy Credit Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 5 |
Remaining performance obligation, 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] | |
Total operating revenues | $ 6 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Retail Energy Sales Contracts In Place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 1 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Capacity And Carbon Free Energy Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 1 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Renewable Energy Credit Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 4 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 9 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Retail Energy Sales Contracts In Place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 0 |
Remaining performance obligation, period | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Capacity And Carbon Free Energy Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 0 |
Remaining performance obligation, period | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Renewable Energy Credit Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 9 |
Remaining performance obligation, period | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 103 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Retail Energy Sales Contracts In Place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | 5 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Capacity And Carbon Free Energy Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | 41 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Renewable Energy Credit Sale Contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 57 |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities - Additional Information (Detail) - USD ($) $ in Millions | Jun. 17, 2019 | Feb. 22, 2019 | Jan. 18, 2019 | Dec. 19, 2018 | Oct. 15, 2018 | Aug. 30, 2018 | May 17, 2018 | Aug. 25, 2014 | Jul. 01, 2014 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Apr. 30, 2019 | Apr. 30, 2018 | Apr. 30, 2017 | Dec. 31, 2018 |
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Unrecorded regulatory assets | $ 1,762 | $ 1,762 | |||||||||||||||||
Equity ratio | 50.00% | ||||||||||||||||||
Public utilities regulatory authority distribution rate | 9.10% | ||||||||||||||||||
Equity ratio, year three | 55.00% | 55.00% | |||||||||||||||||
Rate increase agreement, term | 3 years | ||||||||||||||||||
Regulatory assets | $ 2,801 | $ 2,801 | $ 2,945 | ||||||||||||||||
Unfunded future Income tax expense collection period | 50 years | ||||||||||||||||||
NEW YORK | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 5 years | ||||||||||||||||||
Asset sale gain account | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 5 years | ||||||||||||||||||
Carrying costs on deferred income tax bonus depreciation | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 5 years | ||||||||||||||||||
Economic development | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 5 years | ||||||||||||||||||
Merger capital expense target customer credit | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 5 years | ||||||||||||||||||
Positive benefit adjustment | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 5 years | ||||||||||||||||||
Theoretical reserve flow thru impact | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 5 years | ||||||||||||||||||
UIL Holdings | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Business combination merger related rate credits | 0 | $ 1 | $ 1 | $ 2 | |||||||||||||||
Maximum | NEW YORK | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Deferred income tax recovery period | 39 years | ||||||||||||||||||
Minimum | NEW YORK | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Deferred income tax recovery period | 27 years | ||||||||||||||||||
Electric and Gas Service Rate Plan Year One | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Customer receiving percentage | 50.00% | ||||||||||||||||||
Return on equity | 9.75% | 9.65% | 9.50% | ||||||||||||||||
Electric and Gas Service Rate Plan Year Two | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Customer receiving percentage | 75.00% | ||||||||||||||||||
Return on equity | 10.25% | 10.15% | 10.00% | ||||||||||||||||
Electric and Gas Service Rate Plan Year Three | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Customer receiving percentage | 90.00% | ||||||||||||||||||
Return on equity | 10.75% | 10.65% | 10.50% | ||||||||||||||||
Storm costs | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory assets | $ 342 | $ 342 | $ 346 | ||||||||||||||||
Central Maine Power | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Annual distribution tariff increase | $ 24.3 | ||||||||||||||||||
Distribution tariff rate increased based on ROE | 9.45% | ||||||||||||||||||
Distribution tariff rate increased based on equity capital | 50.00% | ||||||||||||||||||
Recovery of deferred storm costs | 84 | ||||||||||||||||||
Equity ratio | 55.00% | ||||||||||||||||||
Return on equity | 8.75% | 9.35% | |||||||||||||||||
Current Cap On Shared Service Costs | $ 31.4 | ||||||||||||||||||
Public utilities regulatory authority distribution rate | 10.00% | ||||||||||||||||||
Central Maine Power | Maximum | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Proposed tariff rate decrease | $ 3.6 | ||||||||||||||||||
Proposed tariff rate decrease based on ROE | 1.00% | 1.00% | |||||||||||||||||
Central Maine Power | Minimum | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Proposed tariff rate decrease | $ 2 | ||||||||||||||||||
Proposed tariff rate decrease based on ROE | 0.75% | 0.75% | |||||||||||||||||
NYSEG | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Recovery of deferred storm costs | $ 51 | ||||||||||||||||||
Regulatory items amortization period | 3 years | ||||||||||||||||||
Storm costs not included in joint proposal | $ 143 | ||||||||||||||||||
Annual amortization of regulatory items | $ 16.5 | ||||||||||||||||||
Approved return on equity | 9.00% | ||||||||||||||||||
Equity ratio | 48.00% | 48.00% | |||||||||||||||||
NYSEG | Maximum | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Equity ratio for earnings sharing | 50.00% | 50.00% | |||||||||||||||||
NYSEG | Storm costs | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 10 years | ||||||||||||||||||
NYSEG | Regulatory Items Other Than Storm Costs | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 5 years | ||||||||||||||||||
NYSEG | Deferred Income Tax Charge | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 50 years | ||||||||||||||||||
RG&E | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Storm costs not included in joint proposal | $ 52 | ||||||||||||||||||
Approved return on equity | 9.00% | ||||||||||||||||||
Equity ratio | 48.00% | 48.00% | |||||||||||||||||
RG&E | Deferred property tax | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 5 years | ||||||||||||||||||
RG&E | Maximum | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Equity ratio for earnings sharing | 50.00% | 50.00% | |||||||||||||||||
RG&E | Deferred Income Tax Charge | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 50 years | ||||||||||||||||||
Southern Connecticut Gas Company S C G | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Equity ratio | 52.00% | ||||||||||||||||||
Public utilities regulatory authority distribution rate | 9.25% | ||||||||||||||||||
Amount of approved ROE for the year 2018 | $ 1.5 | ||||||||||||||||||
Amount of approved ROE for the year 2019 | 4.7 | ||||||||||||||||||
Amount of approved ROE for the year 2020 | $ 5 | ||||||||||||||||||
Berkshire Gas Company | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Proposed alternative ratemaking mechanism term | 5 years | ||||||||||||||||||
Connecticut Natural Gas Corporation | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Amount of proposed ROE for the year 2019 | $ 9.9 | ||||||||||||||||||
Amount of proposed ROE for the year 2020 | 4.6 | ||||||||||||||||||
Amount of proposed ROE for the year 2021 | 5.2 | ||||||||||||||||||
Amount of proposed ROE, total | $ 19.7 | ||||||||||||||||||
PURA | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Equity ratio | 54.00% | 54.00% | |||||||||||||||||
Percentage of proposed return on equity, year one | 9.30% | ||||||||||||||||||
Equity ratio, year two | 54.50% | 54.50% | |||||||||||||||||
BGC | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Equity ratio | 55.00% | ||||||||||||||||||
Public utilities regulatory authority distribution rate | 9.70% | ||||||||||||||||||
Amount of approved ROE for the year 2018 | $ 1.6 | ||||||||||||||||||
Amount of approved ROE for the year 2019 | $ 0.7 | ||||||||||||||||||
NYSEG | Deferred property tax | |||||||||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||||||||
Regulatory items amortization period | 5 years |
Regulatory Assets and Liabili_4
Regulatory Assets and Liabilities Regulatory Assets and Liabilities - Rate Increases (Details) | May 20, 2019USD ($) |
Electric | NYSEG | |
Regulatory Liabilities [Line Items] | |
Requested Revenue Increase | $ 156.7 |
Delivery Revenue | 20.40% |
Total Revenue | 10.40% |
Electric | RG&E | |
Regulatory Liabilities [Line Items] | |
Requested Revenue Increase | $ 31.7 |
Delivery Revenue | 7.00% |
Total Revenue | 4.10% |
Gas | NYSEG | |
Regulatory Liabilities [Line Items] | |
Requested Revenue Increase | $ 6.3 |
Delivery Revenue | 3.00% |
Total Revenue | 1.40% |
Gas | RG&E | |
Regulatory Liabilities [Line Items] | |
Requested Revenue Increase | $ 5.8 |
Delivery Revenue | 3.30% |
Total Revenue | 1.40% |
Regulatory Assets and Liabili_5
Regulatory Assets and Liabilities - Current and Non-Current Assets (Detail) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 2,801 | $ 2,945 |
Less: current portion | 247 | 299 |
Total non-current regulatory assets | 2,554 | 2,646 |
Pension and other post-retirement benefits cost deferrals | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 135 | 141 |
Pension and other post-retirement benefits | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 1,083 | 1,138 |
Storm costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 342 | 346 |
Rate adjustment mechanism | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 16 | 18 |
Reliability support services | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 2 | 13 |
Revenue decoupling mechanism | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 10 | 7 |
Transmission revenue reconciliation mechanism | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 5 | 11 |
Contracts for differences | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 97 | 97 |
Hardship programs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 26 | 26 |
Plant decommissioning | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 8 | 11 |
Deferred purchased gas | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 1 | 37 |
Deferred transmission expense | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 2 | 11 |
Environmental remediation costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 286 | 278 |
Debt premium | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 102 | 118 |
Unamortized losses on reacquired debt | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 23 | 23 |
Unfunded future income taxes | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 365 | 371 |
Federal tax depreciation normalization adjustment | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 155 | 157 |
Asset retirement obligation | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 18 | 18 |
Deferred meter replacement costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 28 | 29 |
Other | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 97 | $ 95 |
Regulatory Assets and Liabili_6
Regulatory Assets and Liabilities - Current and Non-Current Liabilities (Detail) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 3,542 | $ 3,428 |
Less: current portion | 256 | 205 |
Total non-current regulatory liabilities | 3,286 | 3,223 |
Energy efficiency portfolio standard | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 73 | 56 |
Gas supply charge and deferred natural gas cost | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 17 | 4 |
Pension and other post-retirement benefits cost deferrals | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 98 | 97 |
Carrying costs on deferred income tax bonus depreciation | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 60 | 72 |
Carrying costs on deferred income tax - Mixed Services 263 | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 18 | 20 |
2017 Tax Act | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 1,547 | 1,509 |
Revenue decoupling mechanism | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 21 | 19 |
Accrued removal obligations | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 1,169 | 1,153 |
Asset sale gain account | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 10 | 10 |
Economic development | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 29 | 28 |
Positive benefit adjustment | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 38 | 39 |
Theoretical reserve flow thru impact | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 16 | 19 |
Deferred property tax | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 41 | 25 |
Net plant reconciliation | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 22 | 19 |
Debt rate reconciliation | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 58 | 49 |
Rate refund – FERC ROE proceeding | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 30 | 29 |
Transmission congestion contracts | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 23 | 21 |
Merger-related rate credits | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 17 | 18 |
Accumulated deferred investment tax credits | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 14 | 14 |
Asset retirement obligation | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 13 | 13 |
Earning sharing provisions | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 18 | 17 |
Middletown/Norwalk local transmission network service collections | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 20 | 19 |
Low income programs | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 35 | 38 |
Non-firm margin sharing credits | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 16 | 10 |
Other | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 139 | $ 129 |
Fair Value of Financial Instr_3
Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions | 6 Months Ended | ||||||
Jun. 30, 2019 | Jun. 03, 2019 | May 16, 2019 | Apr. 01, 2019 | Jan. 15, 2019 | Jan. 01, 2019 | Dec. 31, 2018 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Restricted cash | $ 247 | $ 308 | $ 162 | ||||
Fair value of debt | $ 7,276 | 5,952 | |||||
Minimum | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Fair value input, gas or power delivery period (in years) | 2 years | ||||||
Restricted Cash | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Restricted cash | $ 6 | $ 7 | |||||
RG&E | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Percentage of electric load obligations using contracts for a NYISO location | 70.00% | ||||||
Senior Notes Due 2029 through 2049 | Senior Notes | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Debt instrument principal amount | $ 195 | ||||||
Senior Notes Due 2029 through 2049 | Minimum | Senior Notes | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Interest rate | 4.07% | ||||||
Senior Notes Due 2029 through 2049 | Maximum | Senior Notes | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Interest rate | 4.52% | ||||||
Senior Notes Due 2024 | Senior Notes | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Debt instrument principal amount | $ 12 | ||||||
Interest rate | 2.65% | ||||||
Senior Unsecured Notes Due 2029 | Senior Notes | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Debt instrument principal amount | $ 750 | ||||||
Interest rate | 3.80% | ||||||
Senior Notes Due 2026 through 2034 | Senior Notes | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Debt instrument principal amount | $ 240 | ||||||
Senior Notes Due 2026 through 2034 | Minimum | Senior Notes | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Interest rate | 3.87% | ||||||
Senior Notes Due 2026 through 2034 | Maximum | Senior Notes | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Interest rate | 4.20% |
Fair Value of Financial Instr_4
Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Detail) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | $ 91 | $ 79 |
Derivative liabilities | (147) | (141) |
Netting | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | (129) | (114) |
Derivative liabilities | 138 | 99 |
Equity investments with readily determinable fair values | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial instruments, assets | 35 | 37 |
Equity investments with readily determinable fair values | Netting | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial instruments, assets | 0 | 0 |
Derivative financial instruments - power | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 88 | 72 |
Derivative liabilities | (41) | (12) |
Derivative financial instruments - power | Netting | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | (72) | (59) |
Derivative liabilities | 111 | 77 |
Derivative financial instruments - gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 0 | 2 |
Derivative liabilities | (5) | (9) |
Derivative financial instruments - gas | Netting | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | (57) | (55) |
Derivative liabilities | 27 | 22 |
Contracts for differences | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 2 | 5 |
Derivative liabilities | (99) | (102) |
Contracts for differences | Netting | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 0 | 0 |
Derivative liabilities | 0 | 0 |
Derivative financial instruments – other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 1 | |
Derivative liabilities | (2) | (18) |
Derivative financial instruments – other | Netting | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 0 | |
Derivative liabilities | 0 | 0 |
Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 10 | 18 |
Derivative liabilities | (20) | (13) |
Level 1 | Equity investments with readily determinable fair values | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial instruments, assets | 35 | 37 |
Level 1 | Derivative financial instruments - power | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 10 | 17 |
Derivative liabilities | (17) | (12) |
Level 1 | Derivative financial instruments - gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 0 | 1 |
Derivative liabilities | (3) | (1) |
Level 1 | Contracts for differences | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 0 | 0 |
Derivative liabilities | 0 | 0 |
Level 1 | Derivative financial instruments – other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 0 | |
Derivative liabilities | 0 | 0 |
Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 48 | 43 |
Derivative liabilities | (71) | (80) |
Level 2 | Equity investments with readily determinable fair values | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial instruments, assets | 0 | 0 |
Level 2 | Derivative financial instruments - power | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 27 | 23 |
Derivative liabilities | (49) | (41) |
Level 2 | Derivative financial instruments - gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 20 | 20 |
Derivative liabilities | (21) | (23) |
Level 2 | Contracts for differences | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 0 | 0 |
Derivative liabilities | 0 | 0 |
Level 2 | Derivative financial instruments – other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 1 | |
Derivative liabilities | (1) | (16) |
Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 162 | 132 |
Derivative liabilities | (194) | (147) |
Level 3 | Equity investments with readily determinable fair values | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial instruments, assets | 0 | 0 |
Level 3 | Derivative financial instruments - power | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 123 | 91 |
Derivative liabilities | (86) | (36) |
Level 3 | Derivative financial instruments - gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 37 | 36 |
Derivative liabilities | (8) | (7) |
Level 3 | Contracts for differences | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 2 | 5 |
Derivative liabilities | (99) | (102) |
Level 3 | Derivative financial instruments – other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 0 | |
Derivative liabilities | $ (1) | $ (2) |
Fair Value of Financial Instr_5
Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Fair Value, Instruments Classified in Shareholders' Equity Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] (Deprecated 2019-01-31) | ||||
Fair Value Beginning of Period, | $ (22) | $ (9) | $ (15) | $ 6 |
Gains recognized in operating revenues | 14 | 9 | 37 | 14 |
(Losses) recognized in operating revenues | 0 | (2) | (11) | (6) |
Total gains recognized in operating revenues | 14 | 7 | 26 | 8 |
Gains recognized in OCI | 1 | 2 | 0 | 0 |
(Losses) recognized in OCI | 0 | 0 | (13) | 0 |
Total gains recognized in OCI | 1 | 2 | (13) | 0 |
Net change recognized in regulatory assets and liabilities | 2 | 3 | 0 | (8) |
Purchases | (26) | (1) | (26) | (3) |
Settlements | (1) | (3) | (4) | (4) |
Fair Value as of June 30, | (32) | (1) | (32) | (1) |
Gains for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date | $ 14 | $ 7 | $ 26 | $ 8 |
Fair Value of Financial Instr_6
Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Detail) | 6 Months Ended |
Jun. 30, 2019$ / MWh$ / MMBTU | |
NYMEX ($/MMBtu) | Avg. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | $ / MMBTU | 2.92 |
NYMEX ($/MMBtu) | Maximum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | $ / MMBTU | 4.90 |
NYMEX ($/MMBtu) | Minimum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | $ / MMBTU | 2.14 |
Indiana hub ($/MWh) | Avg. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | 30.66 |
Indiana hub ($/MWh) | Maximum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | 61.12 |
Indiana hub ($/MWh) | Minimum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | 19.10 |
Mid C ($/MWh) | Avg. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | 24.86 |
Mid C ($/MWh) | Maximum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | 105 |
Mid C ($/MWh) | Minimum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | (0.50) |
Minn hub ($/MWh) | Avg. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | 25.22 |
Minn hub ($/MWh) | Maximum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | 52.17 |
Minn hub ($/MWh) | Minimum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | 12.51 |
NoIL hub ($/MWh) | Avg. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | 27.46 |
NoIL hub ($/MWh) | Maximum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | 55.39 |
NoIL hub ($/MWh) | Minimum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Variability | 15.50 |
Fair Value of Financial Instr_7
Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Detail) - Contracts for differences - Level 3 | 6 Months Ended |
Jun. 30, 2019$ / MWh | |
Minimum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Risk of non-performance | 0.14% |
Forward pricing ($ per MWh) | 3.8000 |
Minimum | Discount rate | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Discount rate | 0.0176 |
Maximum | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Risk of non-performance | 0.54% |
Forward pricing ($ per MWh) | 7.0300 |
Maximum | Discount rate | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Discount rate | 0.0187 |
Derivative Instruments and He_3
Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Detail) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative Asset | $ 91 | $ 79 |
Derivative Liability | (147) | (141) |
Current Liabilities | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative liabilities | 0 | (16) |
Networks | Current Assets | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Asset | 1 | 8 |
Cash collateral (payable) receivable, Asset | 0 | 0 |
Total derivatives as presented in the balance sheet, Asset | 1 | 8 |
Networks | Current Assets | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 8 | 18 |
Derivative liabilities | (8) | (10) |
Derivative Asset | 0 | 8 |
Networks | Current Assets | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 1 | 0 |
Derivative liabilities | 0 | 0 |
Derivative Asset | 1 | 0 |
Networks | Noncurrent Assets | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Asset | 2 | 3 |
Cash collateral (payable) receivable, Asset | 0 | 0 |
Total derivatives as presented in the balance sheet, Asset | 2 | 3 |
Networks | Noncurrent Assets | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 4 | 6 |
Derivative liabilities | (2) | (3) |
Derivative Asset | 2 | 3 |
Networks | Noncurrent Assets | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 0 | 0 |
Derivative liabilities | 0 | 0 |
Derivative Asset | 0 | 0 |
Networks | Current Liabilities | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Liability | (17) | (13) |
Cash collateral (payable) receivable, Liability | 6 | 0 |
Total derivatives as presented in the balance sheet, Liability | (11) | (13) |
Networks | Current Liabilities | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 8 | 10 |
Derivative liabilities | (24) | (21) |
Derivative Liability | (16) | (11) |
Networks | Current Liabilities | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 0 | 0 |
Derivative liabilities | (1) | (2) |
Derivative Liability | (1) | (2) |
Networks | Noncurrent Liabilities | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Liability | (93) | (90) |
Cash collateral (payable) receivable, Liability | 4 | 0 |
Total derivatives as presented in the balance sheet, Liability | (89) | (90) |
Networks | Noncurrent Liabilities | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 2 | 3 |
Derivative liabilities | (95) | (93) |
Derivative Liability | (93) | (90) |
Networks | Noncurrent Liabilities | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 0 | 0 |
Derivative liabilities | 0 | 0 |
Derivative Liability | 0 | 0 |
Renewables | Current Assets | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Asset | 21 | 16 |
Cash collateral (payable) receivable, Asset | (10) | (8) |
Total derivatives as presented in the balance sheet, Asset | 11 | 8 |
Renewables | Current Assets | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 23 | 19 |
Derivative liabilities | (2) | (5) |
Derivative Asset | 21 | 14 |
Renewables | Current Assets | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 0 | 2 |
Derivative liabilities | 0 | 0 |
Derivative Asset | 0 | 2 |
Renewables | Noncurrent Assets | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Asset | 109 | 94 |
Cash collateral (payable) receivable, Asset | (32) | (34) |
Total derivatives as presented in the balance sheet, Asset | 77 | 60 |
Renewables | Noncurrent Assets | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 121 | 96 |
Derivative liabilities | (8) | (3) |
Derivative Asset | 113 | 93 |
Renewables | Noncurrent Assets | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 1 | 1 |
Derivative liabilities | (5) | 0 |
Derivative Asset | (4) | 1 |
Renewables | Current Liabilities | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Liability | (24) | (24) |
Cash collateral (payable) receivable, Liability | 11 | 9 |
Total derivatives as presented in the balance sheet, Liability | (13) | (15) |
Renewables | Current Liabilities | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 41 | 29 |
Derivative liabilities | (58) | (48) |
Derivative Liability | (17) | (19) |
Renewables | Current Liabilities | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 3 | 2 |
Derivative liabilities | (10) | (7) |
Derivative Liability | (7) | (5) |
Renewables | Noncurrent Liabilities | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Liability | (63) | (24) |
Cash collateral (payable) receivable, Liability | 30 | 17 |
Total derivatives as presented in the balance sheet, Liability | (33) | (7) |
Renewables | Noncurrent Liabilities | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 9 | 17 |
Derivative liabilities | (32) | (35) |
Derivative Liability | (23) | (18) |
Renewables | Noncurrent Liabilities | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 9 | 4 |
Derivative liabilities | (49) | (10) |
Derivative Liability | $ (40) | $ (6) |
Derivative Instruments and He_4
Derivative Instruments and Hedging - Net Notional Volume (Detail) gal in Millions, MWh in Millions, DTH in Millions | 6 Months Ended | 12 Months Ended |
Jun. 30, 2019MWhDTHgal | Dec. 31, 2018MWhDTHgal | |
Networks | Wholesale Electricity Contract | Long | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount | MWh | 4.5 | 4.9 |
Networks | Natural Gas Contracts | Long | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount | 7 | 7.8 |
Networks | Fleet Fuel Contracts | Long | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount | gal | 2.1 | 2.1 |
Renewables and Gas Activities | Long | Basis Swap | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount | 46 | 42 |
Renewables and Gas Activities | Short | Basis Swap | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount | 1 | 4 |
Renewables and Gas Activities | Wholesale Electricity Contract | Long | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount, energy measure (MWh) | MWh | 5 | 5 |
Renewables and Gas Activities | Wholesale Electricity Contract | Short | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount, energy measure (MWh) | MWh | 12 | 6 |
Renewables and Gas Activities | Natural Gas and Other fuel Contracts | Long | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount | 35 | 29 |
Renewables and Gas Activities | Financial Power Contracts | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount | 11 | 11 |
Derivative Instruments and He_5
Derivative Instruments and Hedging - Additional Information (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||||
Jun. 30, 2019 | Jun. 30, 2018 | Dec. 31, 2019 | Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2020 | Jun. 20, 2019 | May 16, 2019 | Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Regulatory Assets | $ 2,801 | $ 2,801 | $ 2,945 | ||||||
Regulatory liabilities | 3,542 | 3,542 | 3,428 | ||||||
UI | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Gross derivative asset | 2 | 2 | 5 | ||||||
Regulatory Assets | 97 | 97 | 97 | ||||||
Gross amounts of recognized liabilities | 99 | 99 | 102 | ||||||
Regulatory liabilities | 0 | $ 0 | 0 | ||||||
Contracts for differences | UI | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Percentage of cost or benefit on contract allocated to customers | 20.00% | ||||||||
Contracts for differences | CL&P | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Percentage of cost or benefit on contract allocated to customers | 80.00% | ||||||||
Gross derivative asset | 0 | $ 0 | 0 | ||||||
Gross amounts of recognized liabilities | 96 | 96 | 96 | ||||||
Interest Rate Swap | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Unrealized gain (loss) from hedging activities reported in accumulated OCI | 39 | ||||||||
Net loss in accumulated OCI related to discontinued cash flow hedge | 0.5 | 0.5 | |||||||
Amortization of net loss | 2 | ||||||||
Networks | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Unrealized gain (loss) from hedging activities reported in accumulated OCI | 0 | $ 0 | 1 | $ 0 | |||||
Networks | Cash Flow Hedging | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Foreign currency exchange risk | $ 100 | ||||||||
Unrealized gain (loss) from hedging activities reported in accumulated OCI | (2) | $ (4) | (2) | $ (4.4) | |||||
Derivative instruments, losses expected to be reclassified into earnings in the next 12 months | $ 1 | ||||||||
Maximum period of time of cash flow hedges | 12 months | ||||||||
Networks | Cash Flow Hedging | Forecast | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Derivative instruments, losses expected to be reclassified into earnings in the next 12 months | $ 1 | ||||||||
Networks | Fuel Derivatives | Cash Flow Hedging | Maximum | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Maximum period of time of cash flow hedges | 12 months | ||||||||
Renewables and Gas Activities | Cash Flow Hedging | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Unrealized gain (loss) from hedging activities reported in accumulated OCI | $ (6) | ||||||||
Renewables and Gas Activities | Cash Flow Hedging | Forecast | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Net loss in accumulated OCI related to discontinued cash flow hedge | $ (2) | ||||||||
Counter Party | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Gross amounts of recognized liabilities | 10 | 10 | |||||||
Cash Collateral Pledged | 12 | 12 | 26 | ||||||
Counter Party | UI | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Derivative collateral obligation to be paid in decrease in credit rating below investment grade | 12 | 12 | |||||||
Swap | Networks | Cash Flow Hedging | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Net loss related to previously settled forward starting swaps | $ 57 | $ 57 | $ 61 | ||||||
Senior Unsecured Notes Due 2029 | Senior Notes | |||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||||||
Debt instrument principal amount | $ 750 |
Derivative Instruments and He_6
Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Dec. 31, 2018 | |
Derivative assets | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Unrealized gain (loss) on derivatives | $ (2) | $ (2) | $ (3) | $ (4) | |
Derivative liabilities | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Unrealized gain (loss) on derivatives | 4 | 6 | 3 | (3) | |
Electricity | Regulatory assets | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Loss or Gain Recognized in Regulatory Assets/Liabilities | 7 | 7 | $ 0 | ||
Unrealized gain (loss) on derivatives | 6 | 1 | 10 | (5) | |
Electricity | Regulatory liabilities | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Loss or Gain Recognized in Regulatory Assets/Liabilities | 5 | ||||
Natural Gas | Regulatory assets | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Loss or Gain Recognized in Regulatory Assets/Liabilities | 3 | 3 | 0 | ||
Unrealized gain (loss) on derivatives | $ 0 | $ 0 | $ 0 | $ 2 | |
Natural Gas | Regulatory liabilities | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Loss or Gain Recognized in Regulatory Assets/Liabilities | $ 0 |
Derivative Instruments and He_7
Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Revenues | $ 1,400 | $ 1,402 | $ 3,242 | $ 3,267 |
Interest Expense | 76 | 70 | 154 | 144 |
Purchased power, natural gas and fuel used | 259 | 279 | 822 | 855 |
Networks | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
(Loss) Gain Recognized in OCI on Derivatives | 0 | 0 | 1 | 0 |
Loss Reclassified from Accumulated OCI into Income | 2 | 2 | 4 | 4 |
Revenues | 1,093 | 1,105 | 2,697 | 2,657 |
Interest rate contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
(Loss) Gain Recognized in OCI on Derivatives | (4) | (4) | (24) | (4) |
Interest rate contracts | Networks | Interest expense | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
(Loss) Gain Recognized in OCI on Derivatives | 0 | 0 | 0 | 0 |
Loss Reclassified from Accumulated OCI into Income | 2 | 2 | 4 | 4 |
Interest rate contracts | Other | Interest expense | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Loss Reclassified from Accumulated OCI into Income | 0 | 0 | 0 | 0 |
Commodity contracts | Networks | Purchased power, natural gas and fuel used | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
(Loss) Gain Recognized in OCI on Derivatives | (1) | 0 | 0 | 0 |
Loss Reclassified from Accumulated OCI into Income | 0 | 0 | 0 | 0 |
Commodity contracts | Renewables and Gas Activities | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
(Loss) Gain Recognized in OCI on Derivatives | 5 | 0 | (15) | (1) |
Commodity contracts | Renewables and Gas Activities | Operating revenues | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Loss Reclassified from Accumulated OCI into Income | 0 | $ 1 | 0 | $ 20 |
Foreign currency exchange contracts | Networks | Purchased power, natural gas and fuel used | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
(Loss) Gain Recognized in OCI on Derivatives | 1 | 1 | ||
Loss Reclassified from Accumulated OCI into Income | $ 0 | $ 0 |
Derivative Instruments and He_8
Derivative Instruments and Hedging - Fair Value of Derivative Contract (Detail) - Renewables and Gas Activities - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative Fair Value, Net | $ 42 | $ 46 |
Financial Power Contracts | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative Fair Value, Net | 71 | 55 |
Long | Wholesale Electricity Contract | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative Fair Value, Net | 28 | 11 |
Long | Natural Gas and Other fuel Contracts | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative Fair Value, Net | (3) | (2) |
Long | Basis Swap | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative Fair Value, Net | (2) | (6) |
Short | Wholesale Electricity Contract | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative Fair Value, Net | $ (52) | $ (12) |
Derivative Instruments and He_9
Derivative Instruments and Hedging - Effect of Trading and Non-trading Derivatives (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total gain included in operating revenues | $ 1,400 | $ 1,402 | $ 3,242 | $ 3,267 |
Total (loss) gain included in purchased power, natural gas and fuel used | 259 | 279 | 822 | 855 |
Renewables and Gas Activities | Trading | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 1 | 2 | 0 | 6 |
Renewables and Gas Activities | Trading | Wholesale Electricity Contract | Long | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 5 | 6 | ||
Renewables and Gas Activities | Trading | Wholesale Electricity Contract | Short | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | (2) | (1) | ||
Renewables and Gas Activities | Trading | Financial Power Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | (1) | (2) | ||
Renewables and Gas Activities | Trading | Financial and Natural Gas Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 0 | 3 | ||
Renewables and Gas Activities | Non-trading | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 19 | (7) | 23 | 2 |
Renewables and Gas Activities | Non-trading | Wholesale Electricity Contract | Long | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 3 | 4 | ||
Renewables and Gas Activities | Non-trading | Wholesale Electricity Contract | Short | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | (7) | (7) | ||
Renewables and Gas Activities | Non-trading | Financial Power Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | (2) | 1 | ||
Renewables and Gas Activities | Non-trading | Financial and Natural Gas Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | $ (1) | $ 4 | ||
Operating revenues | Renewables and Gas Activities | Trading | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 1 | 0 | ||
Operating revenues | Renewables and Gas Activities | Trading | Wholesale Electricity Contract | Long | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | (2) | (1) | ||
Operating revenues | Renewables and Gas Activities | Trading | Wholesale Electricity Contract | Short | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 2 | 2 | ||
Operating revenues | Renewables and Gas Activities | Trading | Financial Power Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 1 | 0 | ||
Operating revenues | Renewables and Gas Activities | Trading | Financial and Natural Gas Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 0 | (1) | ||
Operating revenues | Renewables and Gas Activities | Non-trading | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 28 | 4 | ||
Operating revenues | Renewables and Gas Activities | Non-trading | Wholesale Electricity Contract | Long | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 0 | 0 | ||
Operating revenues | Renewables and Gas Activities | Non-trading | Wholesale Electricity Contract | Short | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 4 | (5) | ||
Operating revenues | Renewables and Gas Activities | Non-trading | Financial Power Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 22 | 9 | ||
Operating revenues | Renewables and Gas Activities | Non-trading | Financial and Natural Gas Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 2 | 0 | ||
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Trading | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 0 | 0 | ||
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Trading | Wholesale Electricity Contract | Long | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 0 | 0 | ||
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Trading | Wholesale Electricity Contract | Short | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 0 | 0 | ||
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Trading | Financial Power Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 0 | 0 | ||
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Trading | Financial and Natural Gas Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 0 | 0 | ||
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Non-trading | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | (9) | 19 | ||
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Non-trading | Wholesale Electricity Contract | Long | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | (3) | 17 | ||
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Non-trading | Wholesale Electricity Contract | Short | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | 0 | 0 | ||
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Non-trading | Financial Power Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | (3) | (2) | ||
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Non-trading | Financial and Natural Gas Contracts | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Total Gain | $ (3) | $ 4 |
Derivative Instruments and H_10
Derivative Instruments and Hedging - Derivative Liabilities (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Designated as hedging instruments | Current Liabilities | ||
Derivative [Line Items] | ||
Derivative liabilities | $ 0 | $ (16) |
Leases - Narrative (Details)
Leases - Narrative (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | 24 Months Ended | ||
Jun. 30, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2017 | |
Lessee, Lease, Description [Line Items] | |||||
Renewal term | 32 years | ||||
Finance lease liabilities | $ 63 | ||||
Operating lease expense | $ 59 | $ 72 | $ 71 | ||
Contingent payments | 11 | 19 | 22 | ||
Minimum | |||||
Lessee, Lease, Description [Line Items] | |||||
Remaining lease term | 1 year | ||||
Maximum | |||||
Lessee, Lease, Description [Line Items] | |||||
Remaining lease term | 64 years | ||||
NYSEG | |||||
Lessee, Lease, Description [Line Items] | |||||
Operating lease expense | 18 | 38 | |||
RG&E | |||||
Lessee, Lease, Description [Line Items] | |||||
Operating lease expense | $ 6 | $ 115 | |||
Monthly lease payments | $ 15 | ||||
Percentage of revenue share | 70.00% | ||||
GNPP | |||||
Lessee, Lease, Description [Line Items] | |||||
Percentage of revenue share | 30.00% | ||||
Renewables | |||||
Lessee, Lease, Description [Line Items] | |||||
Finance lease liabilities | $ 49 | $ 52 | |||
Finance lease term | 15 years | ||||
Early buyout option term | 10 years | ||||
Manufacturing Facility | Renewables | |||||
Lessee, Lease, Description [Line Items] | |||||
Useful life of facility | 25 years |
Leases - Lease Cost (Details)
Leases - Lease Cost (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended |
Jun. 30, 2019 | Jun. 30, 2019 | |
Leases [Abstract] | ||
Amortization of right-of-use assets | $ 3 | $ 6 |
Interest on lease liabilities | 1 | 2 |
Total finance lease cost | 4 | 8 |
Operating lease cost | 3 | 8 |
Short-term lease cost | 1 | 2 |
Variable lease cost | 1 | 1 |
Total lease cost | $ 9 | $ 19 |
Leases - Supplemental Balance S
Leases - Supplemental Balance Sheet (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Jan. 01, 2019 | Dec. 31, 2018 |
Operating Leases | |||
Operating lease right-of-use assets | $ 77 | $ 82 | $ 0 |
Operating lease liabilities, current | 11 | 8 | 0 |
Operating lease liabilities, long-term | 69 | $ 74 | $ 0 |
Total operating lease liabilities | 80 | ||
Finance Leases | |||
Other assets | 139 | ||
Other current liabilities | 8 | ||
Other non-current liabilities | 55 | ||
Total finance lease liabilities | $ 63 | ||
Weighted-average Remaining Lease Term (years): | |||
Finance leases | 8 years 4 days | ||
Operating leases | 13 years 29 days | ||
Weighted-average Discount Rate: | |||
Finance leases | 5.50% | ||
Operating leases | 3.68% |
Leases - Supplemental Cash Flow
Leases - Supplemental Cash Flow (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2019USD ($) | |
Leases [Abstract] | |
Operating cash flows from operating leases | $ 6 |
Operating cash flows from finance leases | 2 |
Financing cash flows from finance leases | 25 |
Finance leases | 0 |
Operating leases | $ (1) |
Leases - Lease Maturities (Deta
Leases - Lease Maturities (Details) $ in Millions | Jun. 30, 2019USD ($) |
Finance Leases | |
July 1, 2019 - December 31, 2019 | $ 3 |
2020 | 10 |
2021 | 6 |
2022 | 2 |
2023 | 50 |
Thereafter | 4 |
Total lease payments | 75 |
Less: imputed interest | (12) |
Total | 63 |
Operating Leases | |
July 1, 2019 - December 31, 2019 | 7 |
2020 | 14 |
2021 | 13 |
2022 | 10 |
2023 | 8 |
Thereafter | 56 |
Total lease payments | 108 |
Less: imputed interest | (28) |
Total | $ 80 |
Leases - Minimum Lease Payments
Leases - Minimum Lease Payments (Details) $ in Millions | Dec. 31, 2018USD ($) |
Operating Leases | |
2019 | $ 31 |
2020 | 39 |
2021 | 38 |
2022 | 35 |
2023 | 33 |
Thereafter | 735 |
Total | 911 |
Capital Leases | |
2019 | 30 |
2020 | 10 |
2021 | 7 |
2022 | 2 |
2023 | 50 |
Thereafter | 2 |
Total | 101 |
Total | |
2019 | 61 |
2020 | 49 |
2021 | 45 |
2022 | 37 |
2023 | 83 |
Thereafter | 737 |
Total | $ 1,012 |
Contingencies (Detail)
Contingencies (Detail) $ in Millions | Feb. 21, 2019USD ($) | May 18, 2018USD ($) | Apr. 30, 2018 | Mar. 22, 2016 | Mar. 03, 2015 | Oct. 16, 2014 | Oct. 31, 2018 | Jun. 30, 2019USD ($) | Dec. 31, 2018USD ($) | Jun. 30, 2018CustomerStorm | Mar. 11, 2017Customer |
Loss Contingencies [Line Items] | |||||||||||
Regulatory liabilities | $ 3,286 | $ 3,223 | |||||||||
Price of the power purchase agreements | 259 | ||||||||||
Requested renewables delay from preliminary proposed ruling period | 2 years | ||||||||||
Standby letters of credit | 513 | ||||||||||
March 2017 Windstorm | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Number of affected customers | Customer | 219,000 | ||||||||||
Investments to increase resiliency and improve emergency response in the areas impacted by the storm | $ 4 | ||||||||||
March 2018 Windstorm | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Number of affected customers | Customer | 520,000 | ||||||||||
Number of severe winter storm | Storm | 2 | ||||||||||
Complaint II | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Regulatory liabilities | 24 | ||||||||||
Complaint III | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Regulatory liabilities | 6 | ||||||||||
Complaint II and III | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Reasonably possible loss, in additional reserve, pre tax | $ 17 | ||||||||||
Unfavorable Regulatory Action | Complaint I | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Approved return on equity | 9.59% | 10.57% | 9.60% | ||||||||
Requested existing base return on equity base percentage | 10.41% | ||||||||||
Unfavorable Regulatory Action | Complaint I | Maximum | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Approved return on equity | 10.42% | 11.74% | 11.74% | 10.99% | |||||||
Requested existing base return on equity base percentage | 13.08% | ||||||||||
Unfavorable Regulatory Action | Complaint III | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Approved return on equity | 10.90% | ||||||||||
Unfavorable Regulatory Action | Complaint III | Maximum | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Approved return on equity | 12.19% | ||||||||||
Before Amendment | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Approved return on equity | 11.14% | ||||||||||
Yankee Companies | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Amount awarded to other party | $ 103 | ||||||||||
Connecticut Yankee | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Amount awarded to other party | 41 | ||||||||||
Maine Yankee | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Amount awarded to other party | 34 | ||||||||||
Yankee Atomic | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Amount awarded to other party | $ 28 |
Environmental Liabilities (Deta
Environmental Liabilities (Detail) $ in Millions | Jul. 05, 2017USD ($) | Sep. 11, 2014USD ($) | Aug. 14, 2013USD ($) | Sep. 09, 2011USD ($) | Nov. 30, 2014USD ($) | Jul. 31, 2011USD ($)site | Jun. 30, 2019USD ($)siteLocation | Dec. 31, 2018USD ($) | Aug. 04, 2016USD ($) |
Environmental Exit Cost [Line Items] | |||||||||
Number of sites with potential remediation obligations | site | 25 | ||||||||
Number of sits note expected to incur additional liabilities | site | 15 | ||||||||
Number of additional sites with liability recorded | site | 11 | ||||||||
Number of sites with liability recorded | site | 10 | ||||||||
Number of sites where gas was manufactured in the past | site | 53,000,000 | ||||||||
Number of sites for which we have entered into consent orders to investigate and remediate | site | 41,000,000 | ||||||||
Costs related to investigation and remediation | $ 362 | $ 366 | |||||||
Accrual for environmental loss contingencies | $ 27 | $ 20 | |||||||
Number of sites with modified decision | site | 9 | ||||||||
Damages for incurred costs payment amount | $ 22 | ||||||||
Refund of environmental remediation cost paid | $ 5 | ||||||||
First Energy | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Former manufactured gas sites | site | 16 | ||||||||
Reasonably possible loss, in additional reserve, net of tax | $ 60 | ||||||||
Environmental costs paid | $ 30 | ||||||||
First Energy | Past Costs | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Accrual for environmental loss contingencies | 27 | ||||||||
First Energy | Pre-judgment Interest | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Environmental costs paid | $ 3 | ||||||||
Century Indemnity and OneBeacon | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Reasonably possible loss, in additional reserve, net of tax | $ 89 | ||||||||
Number of hazardous waste sites | Location | 22 | ||||||||
Asnat | Environmental Remediation Activities | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Pretrial memorandum claiming damages | $ 10 | ||||||||
United Illuminating Company (UI) | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Costs related to investigation and remediation | $ 17 | 20 | $ 30 | ||||||
Maximum | Century Indemnity and OneBeacon | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Reasonably possible loss, in additional reserve, net of tax | $ 282 | ||||||||
New York State Registry | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Number of sites with potential remediation obligations | site | 15 | ||||||||
Number of sites where gas was manufactured in the past | site | 8 | ||||||||
Maine's Uncontrolled Sites Program | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Number of sites with potential remediation obligations | site | 6 | ||||||||
Number of sites where gas was manufactured in the past | site | 2 | ||||||||
Massachusetts Non- Priority Confirmed Disposal Site List | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Number of sites with potential remediation obligations | site | 1 | ||||||||
National Priorities List | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Number of sites with potential remediation obligations | site | 9 | ||||||||
Ten of Twenty-five Sites | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Estimated environmental liability | $ 5 | ||||||||
Another Ten Sites | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Estimated environmental liability | 8 | ||||||||
Another Ten Sites | Minimum | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Estimated environmental liability | 12 | ||||||||
Another Ten Sites | Maximum | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Estimated environmental liability | $ 21 | ||||||||
New York Voluntary Cleanup Program | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Number of sites where gas was manufactured in the past | site | 3 | ||||||||
Maine's Voluntary Response Action Program | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Number of sites where gas was manufactured in the past | site | 3 | ||||||||
Manufactured Gas Plants | Connecticut | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Costs related to investigation and remediation | $ 98 | $ 99 | |||||||
Manufactured Gas Plants | Minimum | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Costs related to investigation and remediation | 176 | ||||||||
Manufactured Gas Plants | Maximum | |||||||||
Environmental Exit Cost [Line Items] | |||||||||
Costs related to investigation and remediation | $ 417 |
Post-Retirement and Similar O_3
Post-Retirement and Similar Obligations - Additional Information (Detail) $ in Millions | 3 Months Ended | 6 Months Ended |
Jun. 30, 2019USD ($) | Jun. 30, 2019USD ($) | |
Retirement Benefits [Abstract] | ||
Defined benefit, pension contributions | $ 12 | $ 19 |
Additional contributions for remainder of fiscal year | $ 46 | $ 46 |
Post-Retirement and Similar O_4
Post-Retirement and Similar Obligations - Periodic Benefit Costs Net (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Pension Plan | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Service cost | $ 10 | $ 11 | $ 20 | $ 22 |
Interest cost | 32 | 32 | 65 | 64 |
Expected return on plan assets | (48) | (50) | (96) | (100) |
Amortization of prior service costs | (1) | 1 | (1) | 1 |
Amortization of actuarial loss | 27 | 37 | 57 | 75 |
Net Periodic Benefit Cost | 20 | 31 | 45 | 62 |
Other Postretirement Benefit Plan | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Service cost | 0 | 1 | 1 | 2 |
Interest cost | 4 | 5 | 8 | 9 |
Expected return on plan assets | (2) | (2) | (4) | (4) |
Amortization of prior service costs | (2) | (2) | (4) | (4) |
Amortization of actuarial loss | (1) | 2 | (1) | 3 |
Net Periodic Benefit Cost | $ (1) | $ 4 | $ 0 | $ 6 |
Equity - Additional Information
Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||
May 31, 2018 | May 31, 2017 | Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Dec. 31, 2016 | Dec. 31, 2018 | |
Class of Stock [Line Items] | |||||||
Common stock, authorized (in shares) | 500,000,000 | 500,000,000 | 500,000,000 | ||||
Common stock, issued (in shares) | 309,752,140 | 309,752,140 | 309,752,140 | ||||
Common stock, outstanding (in shares) | 309,005,272 | 309,005,272 | 309,005,272 | ||||
Common stock, par value (in usd per share) | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | |||
Common stock, issued | $ 3 | $ 3 | $ 3 | ||||
Additional paid-in capital | $ 13,659 | $ 13,659 | $ 13,657 | ||||
Treasury stock, shares (in shares) | 485,810 | 485,810 | 485,810 | ||||
Convertible preferred stock, shares outstanding (in shares) | 0 | 0 | 0 | ||||
Issuances of common stock (in shares) | 0 | 81,208 | |||||
Release of common stock held in trust (in shares) | 0 | 0 | 0 | ||||
Treasury shares of common stock (in shares) | 261,058 | 261,058 | |||||
Repurchases of common stock (in shares) | 81,208 | 64,019 | 115,831 | ||||
Repurchases of common stock | $ 12 | $ 12 | $ 12 | ||||
Iberdrola Renewables Holding, Inc | |||||||
Class of Stock [Line Items] | |||||||
Percentage of equity owned by parent | 81.50% | 81.50% | 81.50% |
Equity - Accumulated Other Comp
Equity - Accumulated Other Comprehensive Gain (Loss) (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||||||||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Mar. 31, 2019 | Jan. 01, 2019 | Dec. 31, 2018 | Mar. 31, 2018 | Jan. 01, 2018 | Dec. 31, 2017 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||||||||
Period Start | $ 15,104 | |||||||||
Adoption of new accounting standards | $ (1) | $ 136 | ||||||||
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit | $ 2 | $ (5) | (27) | $ (5) | ||||||
Other comprehensive income (loss), net of tax | 2 | (4) | (25) | (14) | ||||||
Period End | 15,135 | 15,135 | ||||||||
Other comprehensive income (loss), taxes | (0.7) | 1.3 | 9.5 | 8.5 | ||||||
Accumulated Other Comprehensive Loss | ||||||||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||||||||
Period Start | (111) | (57) | (72) | (46) | ||||||
Adoption of new accounting standards | $ 0 | $ (12) | $ (12) | $ 0 | $ (1) | $ (1) | ||||
Other comprehensive income (loss), net of tax | 2 | (4) | (25) | (14) | ||||||
Period End | (109) | (61) | (109) | (61) | ||||||
Gain on revaluation of defined benefit plans net of tax expense | ||||||||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||||||||
Period Start | (13) | (14) | (11) | (14) | ||||||
Adoption of new accounting standards | (2) | |||||||||
Other comprehensive income (loss), net of tax | 0 | 1 | 0 | 1 | ||||||
Period End | (13) | (13) | (13) | (13) | ||||||
Other comprehensive income (loss), taxes | 0 | 0.2 | 0 | 0.2 | ||||||
Loss on nonqualified pension plans | ||||||||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||||||||
Period Start | (6) | (7) | (6) | (6) | ||||||
Adoption of new accounting standards | $ (1) | |||||||||
Other comprehensive income (loss), net of tax | (1) | (1) | ||||||||
Period End | (7) | (7) | (7) | (7) | ||||||
Loss on derivatives qualifying as cash flow hedges | ||||||||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||||||||
Period Start | (92) | (36) | (55) | (26) | ||||||
Adoption of new accounting standards | (10) | |||||||||
Other comprehensive income (loss), net of tax | 3 | (5) | (24) | (15) | ||||||
Period End | (89) | (41) | (89) | (41) | ||||||
Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense | ||||||||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||||||||
Period Start | (20) | 30 | 9 | 30 | ||||||
Period End | (18) | 25 | (18) | 25 | ||||||
Other comprehensive income (loss), taxes | (0.5) | 1.5 | 10.4 | 1.5 | ||||||
Reclassification to net income of (gains) losses on cash flow hedges, net of income tax (benefit) expense | ||||||||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||||||||
Period Start | (72) | (66) | (64) | (56) | ||||||
Adoption of new accounting standards | $ (10) | |||||||||
Other comprehensive income (loss), net of tax | 1 | 0 | 3 | (10) | ||||||
Period End | (71) | (66) | (71) | (66) | ||||||
Other comprehensive income (loss), taxes | $ (0.2) | $ 0 | $ (0.9) | $ 7.2 |
Earnings Per Share (Detail)
Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Numerator: | ||||
Net income attributable to AVANGRID | $ 110 | $ 107 | $ 327 | $ 351 |
Denominator: | ||||
Weighted average number of shares outstanding - basic (in shares) | 309,491,082 | 309,517,854 | 309,491,082 | 309,515,758 |
Weighted average number of shares outstanding - diluted (in shares) | 309,512,752 | 309,719,584 | 309,509,620 | 309,711,682 |
Earnings per share attributable to AVANGRID | ||||
Earnings Per Common Share, Basic (in usd per share) | $ 0.36 | $ 0.35 | $ 1.06 | $ 1.13 |
Earnings Per Common Share, Diluted (in usd per share) | $ 0.36 | $ 0.34 | $ 1.06 | $ 1.13 |
Segment Information - Additiona
Segment Information - Additional Information (Detail) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019USD ($) | Jun. 30, 2018USD ($) | Jun. 30, 2019USD ($)Segment | Jun. 30, 2018USD ($) | |
Segment Reporting Information [Line Items] | ||||
Number of reportable segments | Segment | 2 | |||
Revenues | $ 1,400 | $ 1,402 | $ 3,242 | $ 3,267 |
Networks | ||||
Segment Reporting Information [Line Items] | ||||
Number of reportable segments | Segment | 1 | |||
Number of operating segments | Segment | 8 | |||
Revenues | 1,093 | 1,105 | $ 2,697 | 2,657 |
Renewables | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 307 | 297 | 549 | 581 |
Electricity | Networks | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 836 | 864 | 1,800 | 1,819 |
Natural Gas | Networks | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 254 | 242 | 890 | 842 |
Other Networks | Networks | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 2 | (3) | 2 | (9) |
Alternative Energy | Renewables | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | $ 307 | $ 296 | $ 549 | $ 579 |
Segment Information - Adjusted
Segment Information - Adjusted Net Income (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Jan. 01, 2019 | Dec. 31, 2018 | |
Segment Reporting Information [Line Items] | ||||||
Revenues | $ 1,400 | $ 1,402 | $ 3,242 | $ 3,267 | ||
Loss from assets held for sale | 0 | 10 | 0 | 15 | ||
Depreciation and amortization | 222 | 215 | 444 | 418 | ||
Operating income (loss) | 207 | 222 | 548 | 625 | ||
Earnings (losses) from equity method investments | 1 | 5 | 2 | 7 | ||
Interest expense, net of capitalization | 76 | 70 | 154 | 144 | ||
Income tax expense (benefit) | 29 | 27 | 70 | 99 | ||
Adjusted net income | 101 | 128 | 319 | 371 | ||
Capital expenditures | 1,337 | 751 | ||||
Property, plant and equipment | 24,373 | 24,373 | $ 23,312 | $ 23,459 | ||
Equity method investments | 505 | 505 | 366 | |||
Total assets | 33,141 | 33,141 | 32,167 | |||
Networks | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 1,093 | 1,105 | 2,697 | 2,657 | ||
Renewables | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 307 | 297 | 549 | 581 | ||
Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 1 | 3 | 1 | 36 | ||
Loss from assets held for sale | 10 | 15 | ||||
Depreciation and amortization | 0 | 0 | 0 | 0 | ||
Operating income (loss) | 3 | (16) | 0 | (1) | ||
Earnings (losses) from equity method investments | 0 | 0 | 0 | 0 | ||
Interest expense, net of capitalization | 7 | (2) | 12 | 4 | ||
Income tax expense (benefit) | 22 | 28 | (2) | 44 | ||
Adjusted net income | (29) | (18) | (16) | (23) | ||
Capital expenditures | 0 | 0 | ||||
Property, plant and equipment | 8 | 8 | 8 | |||
Equity method investments | 0 | 0 | 0 | |||
Total assets | (1,255) | (1,255) | (775) | |||
Operating Segments | Networks | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 1,092 | 1,103 | 2,692 | 2,652 | ||
Loss from assets held for sale | 0 | 0 | ||||
Depreciation and amortization | 135 | 128 | 269 | 246 | ||
Operating income (loss) | 155 | 183 | 486 | 527 | ||
Earnings (losses) from equity method investments | 2 | 4 | 5 | 6 | ||
Interest expense, net of capitalization | 66 | 65 | 135 | 125 | ||
Income tax expense (benefit) | 25 | 23 | 89 | 87 | ||
Adjusted net income | 66 | 79 | 267 | 280 | ||
Capital expenditures | 678 | 522 | ||||
Property, plant and equipment | 15,104 | 15,104 | 14,754 | |||
Equity method investments | 144 | 144 | 142 | |||
Total assets | 22,491 | 22,491 | 22,239 | |||
Operating Segments | Renewables | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 307 | 296 | 549 | 579 | ||
Loss from assets held for sale | 0 | 0 | ||||
Depreciation and amortization | 87 | 87 | 175 | 172 | ||
Operating income (loss) | 49 | 55 | 62 | 99 | ||
Earnings (losses) from equity method investments | (1) | 1 | (3) | 1 | ||
Interest expense, net of capitalization | 2 | 7 | 7 | 15 | ||
Income tax expense (benefit) | (18) | (24) | (17) | (32) | ||
Adjusted net income | 64 | 68 | 69 | 115 | ||
Capital expenditures | 659 | 229 | ||||
Property, plant and equipment | 9,261 | 9,261 | 8,697 | |||
Equity method investments | 361 | 361 | 224 | |||
Total assets | 11,905 | 11,905 | $ 10,703 | |||
Intersegment Eliminations | Networks | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 1 | 2 | 5 | 5 | ||
Intersegment Eliminations | Renewables | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 0 | 1 | 0 | 2 | ||
Intersegment Eliminations | Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | $ (1) | $ (3) | $ (5) | $ (7) |
Segment Information - Reconcili
Segment Information - Reconciliation of Adjusted Net Income to Net Income (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Segment Reporting [Abstract] | ||||
Adjusted Net Income Attributable to Avangrid, Inc. | $ 101 | $ 128 | $ 319 | $ 371 |
Adjustments: | ||||
Loss from assets held for sale | 0 | (10) | 0 | (15) |
Mark-to-market adjustments - Renewables | 20 | (3) | 23 | 1 |
Restructuring charges | (2) | 0 | (2) | (1) |
Accelerated depreciation from repowering | (5) | 0 | (10) | 0 |
Income from release of collateral - Renewables | 0 | 7 | 0 | 7 |
Impact of the Tax Act | 0 | (7) | 0 | (7) |
Income tax impact of adjustments | (3) | (7) | (3) | (17) |
Gas Storage, net of tax | 0 | (2) | 0 | 11 |
Net Income Attributable to Avangrid, Inc. | $ 110 | $ 107 | $ 327 | $ 351 |
Related Party Transactions - Sc
Related Party Transactions - Schedule of Related Party Transactions (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Iberdrola Canada Energy Services, Ltd | ||||
Related Party Transaction [Line Items] | ||||
Purchases From | $ 0 | $ 0 | $ (4) | |
Iberdrola Renovables Energía, S.L. | ||||
Related Party Transaction [Line Items] | ||||
Purchases From | (5) | (4) | $ (9) | (7) |
Iberdrola, S.A. | ||||
Related Party Transaction [Line Items] | ||||
Purchases From | (10) | (12) | (20) | (26) |
Iberdrola Energia Monterrey, S.A. de C.V. | ||||
Related Party Transaction [Line Items] | ||||
Sales To | 3 | |||
Other | ||||
Related Party Transaction [Line Items] | ||||
Sales To | 8 | 0 | 8 | 1 |
Purchases From | $ (1) | $ 0 | $ (2) | $ (1) |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Details) | Jun. 18, 2018USD ($) | Feb. 28, 2019USD ($) | May 31, 2018MW | Jun. 30, 2019USD ($)mi²Megawatts | Jun. 30, 2018USD ($) | Dec. 31, 2018USD ($) |
Related Party Transaction [Line Items] | ||||||
Deposit balance | $ 0 | $ 0 | ||||
Line of credit facility fee basis points | 0.105% | |||||
Credit facility outstanding amount | 0 | 0 | ||||
Affiliated Entity | ||||||
Related Party Transaction [Line Items] | ||||||
Impairments | $ 0 | |||||
New York Transco | ||||||
Related Party Transaction [Line Items] | ||||||
New electric generation and transmission capacity (MW) | Megawatts | 3,200 | |||||
Amount of commitment funded to date | $ 600,000,000 | |||||
Vineyard Wind | ||||||
Related Party Transaction [Line Items] | ||||||
Leased area transmission capacity (MW) | Megawatts | 3,000 | |||||
Proposed wind farm and electricity transmission project capacity (MW) | MW | 800 | |||||
Iberdrola Financiacion, S.A.U | ||||||
Related Party Transaction [Line Items] | ||||||
Line of credit facility, maximum borrowing capacity | $ 500,000,000 | |||||
Iberdrola, S.A. | Siemens-Gamesa | ||||||
Related Party Transaction [Line Items] | ||||||
Business acquisition, percentage of voting interests acquired | 8.10% | |||||
Related party transaction, amount | $ 2,000,000 | $ 6,000,000 | ||||
Networks | New York Transco | ||||||
Related Party Transaction [Line Items] | ||||||
Business combination, equity interest percentage | 20.00% | |||||
Portion of amount receivable from related parties | $ 1,000,000 | 1,000,000 | ||||
Amount of commitment funded to date | $ 120,000,000 | |||||
Renewables | Vineyard Wind | ||||||
Related Party Transaction [Line Items] | ||||||
Business combination, equity interest percentage | 50.00% | |||||
Square mileage of land containing development rights | mi² | 260 | |||||
Portion of amount receivable from related parties | $ 7,000,000 | $ 0 | ||||
Amount of commitment funded to date | $ 100,000,000 | $ 89,000,000 |
Related Party Transactions - _2
Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Siemens-Gamesa | ||
Related Party Transaction [Line Items] | ||
Owed To | $ (14) | $ (14) |
Iberdrola, S.A. | ||
Related Party Transaction [Line Items] | ||
Owed By | 1 | |
Owed To | (20) | (40) |
Iberdrola Renovables Energía, S.L. | ||
Related Party Transaction [Line Items] | ||
Owed By | 4 | 4 |
Owed To | (12) | |
Other | ||
Related Party Transaction [Line Items] | ||
Owed By | 9 | 1 |
Owed To | $ (2) | $ (4) |
Other Financial Statement Ite_3
Other Financial Statement Items - Additional Information (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Dec. 31, 2018 | |
Supplemental Balance Sheet Information [Line Items] | |||||
Loss from assets held for sale | $ 0 | $ 10 | $ 0 | $ 15 | |
Prepaid other taxes | 84 | 84 | $ 137 | ||
Deferred Payment Arrangements | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Accounts receivable | 69 | 69 | 62 | ||
Allowance for doubtful accounts, deferred payment arrangement | $ 34 | 34 | $ 32 | ||
Provision for doubtful accounts, accounts receivable | 1 | $ 2 | |||
Gas Trading and Storage Businesses | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Loss from assets held for sale | $ 10 | $ 15 |
Other Financial Statement Ite_4
Other Financial Statement Items - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Property, plant and equipment | ||
Accumulated depreciation | $ 8,692 | $ 8,359 |
Intangible assets | ||
Accumulated amortization | $ 298 | $ 291 |
Income Tax Expense (Details)
Income Tax Expense (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Income Tax Disclosure [Abstract] | ||||
Effective income tax rate | 21.60% | 19.70% | 17.90% | 22.10% |
Tax expense recorded on disposal of gas business | $ 21.6 |
Stock-Based Compensation Expe_2
Stock-Based Compensation Expense (Detail) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 4 Months Ended | 6 Months Ended | ||
Jun. 30, 2018$ / shares | Jun. 30, 2019USD ($) | Jun. 30, 2018USD ($) | Jun. 30, 2019shares | Jun. 30, 2019USD ($)Installment | Jun. 30, 2018USD ($) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Stock-based compensation expense | $ | $ 1 | $ 0.5 | $ 2 | $ 0.4 | ||
Performance Shares Units | Officers and Employees | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares granted (in shares) | shares | 3,881 | |||||
Number of installment payments of employee related payables | Installment | 3 | |||||
Share-based payment award options grant date fair value (in usd per share) | $ / shares | $ 31.80 |
Variable Interest Entities (Det
Variable Interest Entities (Detail) $ in Millions | Jun. 28, 2019USD ($)MW | Jun. 30, 2019USD ($) | Dec. 31, 2018USD ($) |
Variable Interest Entity [Line Items] | |||
Assets of variable interest entities (VIEs) | $ 1,178 | $ 876 | |
Liabilities of variable interest entities (VIEs) | 60 | 50 | |
Equity method investments of variable interest entities (VIEs) | 505 | 366 | |
Patriot Wind Farm LLC | |||
Variable Interest Entity [Line Items] | |||
Proposed wind farm and electricity transmission project capacity (MW) | MW | 226 | ||
Purchase price | $ 320 | ||
Business combination, property, plant, and equipment | 348 | ||
Business combination, derivative liabilities | 26 | ||
Business combination, other liabilities | 2 | ||
Tax equity financing arrangements - VIEs | $ 128 | ||
Variable Interest Entity, Primary Beneficiary | |||
Variable Interest Entity [Line Items] | |||
Equity method investments of variable interest entities (VIEs) | $ 98 | $ 101 |
Restructuring and Severance R_3
Restructuring and Severance Related Expenses - Additional Information (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Restructuring Reserve [Roll Forward] | ||||
Beginning Balance | $ 4 | |||
Severance Costs | 2 | |||
Payments | (2) | |||
Ending Balance | $ 4 | 4 | ||
Operations and Maintenance | ||||
Restructuring Reserve [Roll Forward] | ||||
Severance Costs | $ 2 | $ 0 | $ 2 | $ 1 |
Subsequent Events (Detail)
Subsequent Events (Detail) - $ / shares | Jul. 16, 2019 | Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 |
Subsequent Event [Line Items] | |||||
Dividends declared (in usd per share) | $ 0.44 | $ 0.432 | $ 0.88 | $ 0.864 | |
Subsequent Event | |||||
Subsequent Event [Line Items] | |||||
Dividends declared (in usd per share) | $ 0.44 |
Uncategorized Items - avangrid2
Label | Element | Value |
Retained Earnings [Member] | ||
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | $ 11,000,000 |
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | (3,000,000) |
Noncontrolling Interest [Member] | ||
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | 140,000,000 |
Parent [Member] | ||
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | (1,000,000) |
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | $ (4,000,000) |