AVANGRID, INC., 10-Q filed on 10/30/2020
Quarterly Report
v3.20.2
Cover Page - shares
9 Months Ended
Sep. 30, 2020
Oct. 29, 2020
Cover [Abstract]    
Document Type 10-Q  
Document Quarterly Report true  
Document Period End Date Sep. 30, 2020  
Document Transition Report false  
Entity File Number 001-37660  
Entity Registrant Name Avangrid, Inc.  
Entity Incorporation, State or Country Code NY  
Entity Tax Identification Number 14-1798693  
Entity Address, Address Line One 180 Marsh Hill Road  
Entity Address, City or Town Orange,  
Entity Address, State or Province CT  
Entity Address, Postal Zip Code 06477  
City Area Code 207  
Local Phone Number 629-1200  
Title of 12(b) Security Common Stock, par value $0.01 per share  
Trading Symbol AGR  
Security Exchange Name NYSE  
Entity Current Reporting Status Yes  
Entity Interactive Data Current Yes  
Entity Filer Category Large Accelerated Filer  
Entity Small Business false  
Entity Emerging Growth Company false  
Entity Shell Company false  
Entity Common Stock, Shares Outstanding (in shares)   309,009,817
Amendment Flag false  
Document Fiscal Year Focus 2020  
Document Fiscal Period Focus Q3  
Entity Central Index Key 0001634997  
Current Fiscal Year End Date --12-31  
v3.20.2
Condensed Consolidated Statements of Income (unaudited) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Income Statement [Abstract]        
Operating Revenues $ 1,470 $ 1,487 $ 4,651 $ 4,729
Operating Expenses        
Purchased power, natural gas and fuel used 259 279 999 1,101
Operations and maintenance 634 588 1,788 1,714
Depreciation and amortization 255 237 748 681
Taxes other than income taxes 157 144 469 446
Total Operating Expenses 1,305 1,248 4,004 3,942
Operating Income 165 239 647 787
Other Income and (Expense)        
Other income 16 6 15 1
Earnings (losses) from equity method investments 1 (1) (3) 1
Interest expense, net of capitalization (86) (72) (251) (226)
Income Before Income Tax 96 172 408 563
Income tax expense 15 33 21 103
Net Income 81 139 387 460
Net loss attributable to noncontrolling interests 6 11 28 17
Net Income Attributable to Avangrid, Inc. $ 87 $ 150 $ 415 $ 477
Earnings Per Common Share, Basic (in usd per share) $ 0.28 $ 0.48 $ 1.34 $ 1.54
Earnings Per Common Share, Diluted (in usd per share) $ 0.28 $ 0.48 $ 1.34 $ 1.54
Weighted-average Number of Common Shares Outstanding:        
Basic (in shares) 309,491,082 309,491,082 309,496,234 309,491,082
Diluted (in shares) 309,550,126 309,517,778 309,554,838 309,512,301
v3.20.2
Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Statement of Comprehensive Income [Abstract]        
Net Income $ 81 $ 139 $ 387 $ 460
Other Comprehensive Income (Loss)        
Loss on nonqualified pension plans 0 0 0 (1)
Unrealized (loss) gain during the period on derivatives qualifying as cash flow hedges, net of income tax of $(3) and $2 for the three months ended, respectively, and $(8) for both the nine months ended (15) 5 (31) (22)
Reclassification to net income of loss on cash flow hedges, net of income taxes of $0 and $1 for both the three months ended, respectively, and $1 and $2 for the nine months ended, respectively 9 5 12 8
Other Comprehensive Income (Loss) (6) 10 (19) (15)
Comprehensive Income 75 149 368 445
Net loss attributable to noncontrolling interests 6 11 28 17
Comprehensive Income Attributable to Avangrid, Inc. 81 160 396 462
Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, tax $ (3) $ 2 $ (8) $ (8)
v3.20.2
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Statement of Comprehensive Income [Abstract]        
Unrealized (loss) gain during the period on derivatives qualifying as cash flow hedges, tax $ (3) $ 2 $ (8) $ (8)
Reclassification to net income of loss on cash flow hedges, tax expense (benefit) $ 0 $ 1 $ 1 $ 2
v3.20.2
Condensed Consolidated Balance Sheets (unaudited) - USD ($)
$ in Millions
Sep. 30, 2020
Dec. 31, 2019
Current Assets    
Cash and cash equivalents $ 101 $ 178
Accounts receivable and unbilled revenues, net 1,021 1,082
Accounts receivable from affiliates 7 10
Derivative assets 19 11
Fuel and gas in storage 100 110
Materials and supplies 157 141
Prepayments and other current assets 266 199
Regulatory assets 252 294
Total Current Assets 1,923 2,025
Total Property, Plant and Equipment ($1,657 and $787 related to VIEs, respectively) 26,432 25,218
Operating lease right-of-use assets 68 70
Equity method investments 668 645
Other investments 61 63
Regulatory assets 2,591 2,567
Other Assets    
Goodwill 3,119 3,119
Intangible assets 307 314
Derivative assets 85 84
Other 386 311
Total Other Assets 3,897 3,828
Total Assets 35,640 34,416
Current Liabilities    
Current portion of debt 813 730
Notes payable 998 560
Notes payable to affiliates 4 0
Interest accrued 87 72
Accounts payable and accrued liabilities 1,481 1,361
Accounts payable to affiliates 43 64
Dividends payable 136 136
Taxes accrued 82 56
Operating lease liabilities 11 12
Derivative liabilities 19 20
Other current liabilities 296 334
Regulatory liabilities 214 242
Total Current Liabilities 4,184 3,587
Regulatory liabilities 3,342 3,281
Other Non-current Liabilities    
Deferred income taxes 1,846 1,814
Deferred income 1,221 1,274
Pension and other postretirement 998 1,100
Operating lease liabilities 42 65
Derivative liabilities 81 85
Asset retirement obligations 208 190
Environmental remediation costs 333 338
Other 450 380
Total Other Non-current Liabilities 5,179 5,246
Non-current debt 7,081 6,716
Total Non-current Liabilities 15,602 15,243
Total Liabilities 19,786 18,830
Commitments and Contingencies
Stockholders’ Equity:    
Common stock, $.01 par value, 500,000,000 shares authorized, 309,794,917 and 309,752,140 shares issued; 309,005,485 and 309,005,272 shares outstanding, respectively 3 3
Additional paid in capital 13,664 13,660
Treasury stock (14) (12)
Retained earnings 1,684 1,681
Accumulated other comprehensive loss (114) (95)
Total Stockholders’ Equity 15,223 15,237
Non-controlling interests 631 349
Total Equity 15,854 15,586
Total Liabilities and Equity $ 35,640 $ 34,416
v3.20.2
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($)
$ in Millions
Sep. 30, 2020
Dec. 31, 2019
Sep. 30, 2019
Property, plant and equipment $ 26,432 $ 25,218  
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) 309,794,917 309,752,140  
Common stock, outstanding (in shares) 309,005,485 309,005,272  
Variable Interest Entity, Primary Beneficiary      
Property, plant and equipment $ 1,657   $ 787
v3.20.2
Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($)
$ in Millions
9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Cash Flow from Operating Activities:    
Net Income $ 387 $ 460
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization 748 681
Regulatory assets/liabilities amortization and carrying cost 63 51
Pension cost 60 68
Earnings (losses) from equity method investments 3 (1)
Distributions of earnings received from equity method investments 15 10
Unrealized gain on marked-to-market derivative contracts (9) (66)
Deferred taxes 11 99
Other non-cash items (35) (35)
Changes in operating assets and liabilities:    
Current assets 7 188
Noncurrent assets (152) (24)
Current liabilities 24 (73)
Noncurrent liabilities (30) (114)
Net Cash Provided by Operating Activities 1,092 1,244
Cash Flow from Investing Activities:    
Capital expenditures (1,960) (2,045)
Contributions in aid of construction 35 36
Proceeds from sale of assets 12 13
Proceeds from notes receivable from affiliates 2 0
Distributions received from equity method investments 3 4
Other investments and equity method investments, net (48) (164)
Net Cash Used in Investing Activities (1,956) (2,156)
Cash Flow from Financing Activities:    
Non-current debt issuances 967 1,637
Repayments of non-current debt (511) (344)
Receipts of other short-term debt, net 441 32
Repayments of financing leases (7) (26)
Repurchase of common stock (2) 0
Issuance of common stock (1) 0
Distributions to noncontrolling interests (5) (47)
Contributions from noncontrolling interests 312 133
Dividends paid (408) (408)
Net Cash Provided by Financing Activities 786 977
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash (78) 65
Cash, Cash Equivalents and Restricted Cash, Beginning of Period 184 43
Cash, Cash Equivalents and Restricted Cash, End of Period 106 108
Supplemental Cash Flow Information    
Cash paid for interest, net of amounts capitalized 206 183
Cash paid for income taxes $ 4 $ 4
v3.20.2
Condensed Consolidated Statements of Changes in Equity (unaudited) - USD ($)
$ in Millions
Total
Cumulative Effect, Period of Adoption, Adjustment
Common Stock
Additional paid-in capital
Treasury Stock
Retained Earnings
Retained Earnings
Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Loss
Cumulative Effect, Period of Adoption, Adjustment
Total Stockholders’ Equity
Total Stockholders’ Equity
Cumulative Effect, Period of Adoption, Adjustment
Noncontrolling Interests
Noncontrolling Interests
Cumulative Effect, Period of Adoption, Adjustment
Balance, beginning of period (in shares) at Dec. 31, 2018 [1]     309,005,272                    
Balance, beginning of period at Dec. 31, 2018 $ 15,403 $ (1) $ 3 $ 13,657 $ (12) $ 1,528 $ 11 $ (72) $ (12) $ 15,104 $ (1) $ 299 $ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]                          
Net income (loss) 460         477       477   (17)  
Other Comprehensive Income (Loss) (15)             (15)   (15)      
Comprehensive Income 445                        
Dividends declared (408)         (408)       (408)      
Stock-based compensation 2     2           2      
Distributions to noncontrolling interests (47)                     (47)  
Contributions from noncontrolling interests 124         (9)       (9)   133  
Balance, end of period (in shares) at Sep. 30, 2019 [1]     309,005,272                    
Balance, end of period at Sep. 30, 2019 15,518   $ 3 13,659 (12) 1,599   (99)   15,150   368  
Balance, beginning of period (in shares) at Jun. 30, 2019 [1]     309,005,272                    
Balance, beginning of period at Jun. 30, 2019 15,549   $ 3 13,659 (12) 1,594   (109)   15,135   414  
Increase (Decrease) in Stockholders' Equity [Roll Forward]                          
Net income (loss) 139         150       150   (11)  
Other Comprehensive Income (Loss) 10             10   10      
Comprehensive Income 149                        
Dividends declared (136)         (136)       (136)      
Distributions to noncontrolling interests (37)                     (37)  
Contributions from noncontrolling interests (7)         (9)       (9)   2  
Balance, end of period (in shares) at Sep. 30, 2019 [1]     309,005,272                    
Balance, end of period at Sep. 30, 2019 $ 15,518   $ 3 13,659 (12) 1,599   (99)   15,150   368  
Balance, beginning of period (in shares) at Dec. 31, 2019 309,005,272   309,005,272 [1]                    
Balance, beginning of period at Dec. 31, 2019 $ 15,586 $ (1) $ 3 13,660 (12) 1,681 $ (1) (95)   15,237 $ (1) 349  
Increase (Decrease) in Stockholders' Equity [Roll Forward]                          
Net income (loss) 387         415       415   (28)  
Other Comprehensive Income (Loss) (19)             (19)   (19)      
Comprehensive Income 368                        
Dividends declared (408)         (408)       (408)      
Release of common stock held in trust (in shares) [1]     213                    
Issuances of common stock (in shares) [1]     42,777                    
Issuance of common stock (1)     (1)           (1)      
Repurchase of common stock (in shares) [1]     (42,777)                    
Repurchase of common stock (2)       (2)         (2)      
Stock-based compensation 5     5           5      
Distributions to noncontrolling interests (5)                     (5)  
Contributions from noncontrolling interests $ 312         (3)       (3)   315  
Balance, end of period (in shares) at Sep. 30, 2020 309,005,485   309,005,485 [1]                    
Balance, end of period at Sep. 30, 2020 $ 15,854   $ 3 13,664 (14) 1,684   (114)   15,223   631  
Balance, beginning of period (in shares) at Jun. 30, 2020 [1]     309,005,485                    
Balance, beginning of period at Jun. 30, 2020 15,916   $ 3 13,664 (14) 1,733   (108)   15,278   638  
Increase (Decrease) in Stockholders' Equity [Roll Forward]                          
Net income (loss) 81         87       87   (6)  
Other Comprehensive Income (Loss) (6)             (6)   (6)      
Comprehensive Income 75                        
Dividends declared (136)         (136)       (136)      
Distributions to noncontrolling interests $ (1)                     (1)  
Balance, end of period (in shares) at Sep. 30, 2020 309,005,485   309,005,485 [1]                    
Balance, end of period at Sep. 30, 2020 $ 15,854   $ 3 $ 13,664 $ (14) $ 1,684   $ (114)   $ 15,223   $ 631  
[1] (*) Par value of share amounts is $0.01
v3.20.2
Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Statement of Stockholders' Equity [Abstract]        
Common stock, par value (in USD per share) $ 0.01   $ 0.01  
Other comprehensive income (loss), taxes $ (3) $ 3 $ (7) $ (6)
Dividends declared (in usd per share) $ 0.44 $ 0.44 $ 1.32 $ 1.32
v3.20.2
Background and Nature of Operations
9 Months Ended
Sep. 30, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Background and Nature of Operations Background and Nature of OperationsAvangrid, 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.
v3.20.2
Basis of Presentation
9 Months Ended
Sep. 30, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Basis of Presentation Basis of Presentation
The accompanying condensed consolidated financial statements should be read in conjunction with the Form 10-K for the fiscal year ended December 31, 2019.
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.
Preparation of the accompanying unaudited financial statements requires management to make estimates and assumptions that affect the amounts reported during the periods covered by the related financial statements and accompanying disclosures. We continue to utilize information reasonably available to us; however, the business and economic uncertainty resulting from the global pandemic of the novel coronavirus (COVID-19) has made such estimates and assumptions more difficult to assess and calculate. Impacted estimates include, but are not limited to, evaluations of certain long-lived assets and goodwill for impairment, expected credit losses and potential regulatory deferral or recovery of certain costs. While there were no material impacts from COVID-19 on financial results, actual results could differ from those estimates, which could result in material impacts to our consolidated financial statements in future reporting periods.
In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated financial statements 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 nine months ended September 30, 2020, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2020.
v3.20.2
Significant Accounting Policies and New Accounting Pronouncements
9 Months Ended
Sep. 30, 2020
Accounting Policies [Abstract]  
Significant Accounting Policies and New Accounting Pronouncements Significant Accounting Policies and New Accounting Pronouncements
The new accounting pronouncements that we have adopted as of January 1, 2020, 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 Form 10-K for the fiscal year ended December 31, 2019, except for those described below resulting from the adoption of new authoritative accounting guidance issued by Financial Accounting Standards Board (FASB).
Goodwill
Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed.
Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. If we determine, based on qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass the qualitative assessment, or perform the qualitative assessment but determine that it is more likely than not that its fair value is
less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit.
Accounts receivable and unbilled revenue, net
We record accounts receivable at amounts billed to customers and we record unbilled revenues based on an estimate of energy delivered or services provided to customers. Certain accounts receivable and payable related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services, and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances and they are settled on a net basis. We present receivables and payables subject to such agreements on a net basis on our consolidated balance sheets.
Accounts receivable include amounts due under Deferred Payment Arrangements (DPAs). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies 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 short term.
We establish our allowance for credit losses, including for unbilled revenue, by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. Due to our adoption of Accounting Standards Codification (ASC) 326 effective January 1, 2020, we now also consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the accounts receivable. We write off amounts when we have exhausted reasonable collection efforts.
Adoption of New Accounting Pronouncements
(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 (ASC 326). 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 collectability 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 ASC 326 to clarify transition and scope requirements, make narrow-scope codification improvements, including in March 2020, and corrections and provide targeted transition relief. We adopted the amendments effective January 1, 2020, including the narrow-scope improvements issued in March 2020, and recorded a cumulative-effect adjustment of $1 million to retained earnings at the beginning of the period of adoption, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures.
(b) Simplifying the test for goodwill impairment
In January 2017, the FASB issued amendments to simplify the test for goodwill impairment, which are required for public entities and certain other entities that have goodwill reported in their financial statements. The amendments simplify the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test, which requires the valuation of assets acquired and liabilities assumed using business combination accounting guidance. Under the new guidance, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; but the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Also, an entity should consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. Certain requirements are eliminated for any reporting unit with a
zero or negative carrying amount; therefore, the same impairment assessment applies to all reporting units. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. As required, we will apply the amendments on a prospective basis.
(c) Changes to the disclosure requirements for fair value measurement and defined benefit plans
In August 2018, the FASB issued amendments related to disclosure requirements for both fair value measurement and defined benefit plans.
The amendments concerning fair value measurement remove, modify and add certain disclosure requirements in order to improve the overall usefulness of the disclosures and reduce unnecessary costs to companies to prepare the disclosures. We adopted the amendments effective January 1, 2020, with no material effect to our disclosures. Certain amendments are to be applied prospectively, and all others are to be applied retrospectively.
The amendments concerning disclosure requirements for defined benefit plans are narrow in scope and apply to all employers that sponsor defined benefit pension or other postretirement plans. The amendments change annual disclosures requirements, including removal of disclosures that are no longer considered cost beneficial, adding certain new relevant disclosures and clarifying specific requirements of disclosures concerning information for defined benefit pension plans. We adopted the amendments effective January 1, 2020, and they will not materially affect the disclosures for our fiscal year ending December 31, 2020. As required, our application will be on a retrospective basis.
(d) Targeted improvements to related party guidance for VIEs
In October 2018, the FASB issued amendments that affect reporting entities that are required to determine whether they should consolidate a legal entity under the consolidation guidance applicable to VIEs. The targeted improvements specifically applicable to public business entities clarify that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures.
(e) Clarifying guidance for certain collaborative arrangements with respect to revenue recognition
The FASB issued amendments in November 2018 to clarify the interaction between the guidance for certain collaborative arrangements and the guidance applicable to ASC 606. A collaborative arrangement is a contractual arrangement under which two or more parties actively participate in a joint operating activity and are exposed to significant risks and rewards that depend on the activity’s commercial success. The targeted improvements clarify that certain transactions between collaborative arrangement participants are within the scope of ASC 606 and thus subject to all of its guidance. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. As required, we retrospectively applied the amendments to the date of our initial application of ASC 606.
Accounting Pronouncements Issued But Not Yet Adopted
The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2019, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.
(a) Simplifying the accounting for income taxes
In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes, eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation; (2) exceptions to accounting for basis differences in equity method investments when there are ownership changes in foreign investments; and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for: (1) franchise taxes that are partially based on income; (2) transactions with a government that result in a step up in the tax basis of goodwill; (3) separate financial statements of legal entities that are not subject to tax; and (4) enacted changes in tax laws in interim periods. The amendments are effective for public business entities for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued, with adoption of all amendments in the same period. Application is on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment aspect. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows.
(b) Facilitation of the effects of reference rate reform on financial reporting
In March 2020, the FASB issued amendments to provide temporary optional guidance to entities to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments respond to concerns about structural risks of interbank offered rates, and particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR). The guidance is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform, around the end of 2021. The guidance applies to contracts that have modified terms that affect, or have the potential to affect, the amount or timing of contractual cash flows resulting from the discontinuance of the reference rate reform. The amendments are effective for all entities as of March 12, 2020, through December 31, 2022, although the FASB has indicated it will monitor developments in the marketplace and consider whether developments warrant an extension. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows.
v3.20.2
Revenue
9 Months Ended
Sep. 30, 2020
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 our reportable segments, refer to Note 13.
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 (RDMs), 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 ASC 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 ASC 606 revenue, which we recognize based on the amount invoiced to the customer.
Other
Other, which does not represent a segment, includes miscellaneous Corporate revenues and 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 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 prior costs incurred to cancel a PPA, which are related to the wind farm interest that is being sold as described in Note 15. Contract assets totaled $12 million at both September 30, 2020 and December 31, 2019, 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 $6 million and $10 million at September 30, 2020 and December 31, 2019, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $6 million and $16 million as revenue during the three and nine months ended September 30, 2020, respectively, and $7 million and $16 million for the three and nine months ended September 30, 2019, respectively.
Revenues disaggregated by major source for our reportable segments for the three and nine months ended September 30, 2020 and 2019 are as follows:
 Three Months Ended September 30, 2020Nine Months Ended September 30, 2020
 NetworksRenewablesOther (b)TotalNetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity
$984 $— $— $984 $2,701 $— $— $2,701 
Regulated operations – natural gas
166 — — 166 910 — — 910 
Nonregulated operations – wind
— 200 — 200 — 639 — 639 
Nonregulated operations – solar
— — — 16 — 16 
Nonregulated operations – thermal
— 13 — 13 — 27 — 27 
Other(a)12 28 (4)36 38 75 (4)109 
Revenue from contracts with customers
1,162 247 (4)1,405 3,649 757 (4)4,402 
Leasing revenue— — — — 
Derivative revenue — 25 — 25 — 111 — 111 
Alternative revenue programs
24 — — 24 109 — — 109 
Other revenue14 16 — 24 
Total operating revenues
$1,197 $276 $(3)$1,470 $3,779 $876 $(4)$4,651 
Three Months Ended September 30, 2019Nine Months Ended September 30, 2019
NetworksRenewablesOther (b)TotalNetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity
$922 $— $— $922 $2,637 $— $— $2,637 
Regulated operations – natural gas
179 — — 179 1,053 — — 1,053 
Nonregulated operations – wind
— 218 — 218 — 621 — 621 
Nonregulated operations – solar
— — — 22 — 22 
Nonregulated operations – thermal
— — — 21 — 21 
Other(a)16 23 — 39 71 40 (4)107 
Revenue from contracts with customers
1,117 255  1,372 3,761 704 (4)4,461 
Leasing revenue— — — — 
Derivative revenue — 84 — 84 — 173 — 173 
Alternative revenue programs
13 — — 13 48 — — 48 
Other revenue— 17 23 19 — 42 
Total operating revenues
$1,140 $347 $ $1,487 $3,837 $896 $(4)$4,729 
(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 and intersegment eliminations.
As of September 30, 2020 and December 31, 2019, accounts receivable balances related to contracts with customers were approximately $988 million and $1,050 million, respectively, including unbilled revenues of $266 million and $345 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.
As of September 30, 2020, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:
As of September 30, 202020212022202320242025ThereafterTotal
(Millions)       
Revenue expected to be recognized on multiyear retail energy sales contracts in place
$$$$$— $— $
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
39 23 15 12 11 75 175 
Revenue expected to be recognized on multiyear renewable energy credit sale contracts
27 18 66 
Total operating revenues$67 $42 $25 $17 $14 $80 $245 
As of September 30, 2020, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2020 was $24 million.
v3.20.2
Regulatory Assets and Liabilities
9 Months Ended
Sep. 30, 2020
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 regulatory 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 rate base or accruing carrying costs are 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 $1,616 million.
CMP Rate Case
In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17 million, or approximately 7%, based on an allowed ROE of 9.25% and a 50% equity ratio. The rate increase was effective March 1, 2020. The MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a period of 18 consecutive months, which commenced on March 1, 2020. CMP has satisfied all four of these quality measures since the measurement period commenced.
The order provided additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC order also retained the RDM implemented in 2014. The order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine ratepayers. The management audit was commenced in July 2020 by the MPUC’s consultants and is expected to conclude in December 2020.
CMP Revenue Decoupling Mechanism Investigation
On June 9, 2020, the MPUC issued a Notice of Investigation to open an investigation into the effects of the COVID-19 pandemic on customers’ electricity-usage patterns and whether CMP’s RDM should be suspended for the annual distribution rate change that is expected to occur on July 1, 2021, for electricity delivered in calendar year 2020. On June 24, 2020, the MPUC issued a procedural order setting forth initial steps in this proceeding. On July 21, 2020, CMP filed testimony presenting electricity-usage data for its two RDM classes (residential and commercial/industrial) through June 2020, along with testimony explaining the data and the reasons why the current RDM should remain in place without alteration. We cannot predict the outcome of this matter.
NYSEG and RG&E Rate Plans and Rate Case Filings
Current Rate Plan
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 a portion of storm costs to be recovered over ten 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.
Rate Case Filing Update
On May 20, 2019, NYSEG and RG&E filed rate cases with the NYPSC for new tariffs.
On March 23, 2020, the Public Utility Law Project (a party to the cases) submitted a letter motion requesting that the NYPSC administrative law judges assigned to preside over the rate cases require NYSEG and RG&E to pause settlement discussions and to provide new and accurate calculations based on the current and future expected economic impact of the COVID-19 pandemic. On March 31, 2020, NYSEG and RG&E, Multiple Intervenors (a party to the cases) and NYDPS staff each filed a response in opposition to the motion. On April 7, 2020, the NYPSC administrative law judges issued a Ruling Denying Public Utility Law Project’s Motion, allowing settlement negotiations to continue. On April 22, 2020, the Public Utility Law Project and AARP filed an interlocutory appeal requesting that the NYPSC review the determination of the administrative law judges. We cannot predict the outcome of this proceeding.
On June 22, 2020, NYSEG and RG&E filed a joint proposal with the NYPSC for a new three-year rate plan. The effective date of new tariffs was November 1, 2020 with a make-whole provision back to April 17, 2020. We were granted a one month extension making the new effective date December 1, 2020, pending NYPSC approval of the joint proposal. The proposed rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as COVID-19 relief for customers and additional funding for vegetation management, hardening/resiliency and emergency preparedness. The joint proposal bases delivery revenues on an 8.80% ROE and 48% equity ratio; however, for the proposed earnings sharing mechanism, the equity ratio is the lower of the actual equity ratio or 50%. The below table provides a summary of the proposed delivery rate increases and delivery rate percentages, including rate levelization and excluding energy efficiency, which is a pass-through, for all four businesses:
Year 1Year 2Year 3
Rate IncreaseDelivery Rate %Rate IncreaseDelivery Rate %Rate IncreaseDelivery Rate %
Utility(Millions)Increase(Millions)Increase(Millions)Increase
NYSEG Electric$34.7 4.6 %$71.51 9.1 %$79.4 9.1 %
NYSEG Gas$— — %$1.58 0.8 %$3.3 1.6 %
RG&E Electric$10.7 2.4 %$22.92 5.2 %$25.4 5.2 %
RG&E Gas$— — %$— — %$2.4 1.3 %
The rate plans continue the RAM designed to return or collect certain defined reconciled revenues and costs, have new depreciation rates and continue existing RDMs for each business. Statements in support or opposition and reply statements were filed in July 2020, and a final decision by the NYPSC is expected during the fourth quarter of 2020. We cannot predict the outcome of this proceeding.
UI, CNG, SCG and BCG Rate Plans
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 $2 million, $5 million and $5 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 an 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.
In December 2018, PURA approved new tariffs for CNG effective January 1, 2019 for a three-year rate plan with rate increases of $10 million, $5 million and $5 million in 2019, 2020 and 2021, respectively. The new tariffs continued the RDM and DIMP mechanism. ESM and tariff increases are 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 new distribution rates for BGC providing for a $2 million distribution base rate increase effective February 1, 2019 (with a make-whole provision back to January 1, 2019), and an additional $1 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 new tariffs provide for the implementation of an RDM and pension expense tracker and also provide that BGC will not file to change base distribution rates to become effective before November 1, 2021.
Connecticut Storm Reimbursement Legislation
On October 7, 2020, the Governor of Connecticut signed into law an energy bill that, among other things, instructs PURA to revise the rate-making structure in Connecticut to adopt performance-based rates for each electric distribution company, increases the maximum civil penalties assessable for failures in emergency preparedness, and provides certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines.
Regulatory assets and liabilities
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 September 30, 2020 and December 31, 2019, respectively, consisted of:
September 30,December 31,
As of20202019
(Millions)
Pension and other post-retirement benefits cost deferrals$101 $125 
Pension and other post-retirement benefits963 1,061 
Storm costs418 272 
Rate adjustment mechanism 16 79 
Revenue decoupling mechanism56 19 
Transmission revenue reconciliation mechanism
Contracts for differences90 92 
Hardship programs26 29 
Plant decommissioning— 
Deferred purchased gas14 25 
Deferred transmission expense14 11 
Environmental remediation costs278 277 
Debt premium88 97 
Unamortized losses on reacquired debt27 29 
Unfunded future income taxes408 399 
Federal tax depreciation normalization adjustment149 153 
Asset retirement obligation21 17 
Deferred meter replacement costs25 27 
COVID-19 cost recovery2
Other138 139 
Total regulatory assets2,843 2,861 
Less: current portion252 294 
Total non-current regulatory assets$2,591 $2,567 
“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 September 30, 2020, deferred storm costs include $69 million and $16 million at NYSEG being recovered over ten-year and five-year periods, respectively, beginning in 2016, and $196 million and $61 million at NYSEG and RG&E, respectively, not included in the Joint Proposal. The amounts not included in the Joint Proposal will be recovered through RAM or determined as part of the current rate proceedings.
“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.
"Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales.
"Transmission revenue reconciliation mechanism" reflects differences in actual costs in the rate year from those used to set rates. This mechanism contains the Annual Transmission True up (ATU), which is recovered over the subsequent June to May period.
“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.
“Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.
“Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates.
“Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements.
“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.
“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.
“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.
“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 unfunded future 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. These amounts are being 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.
“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 32.5 years beginning in 2020.
“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.
“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.
"COVID-19 cost recovery" represents deferred COVID-19-related costs in the state of Connecticut based on the order issued by PURA on April 29, 2020, requiring utilities to track COVID-19-related expenses and lost revenue and create a regulatory asset.
“Other” includes post-term amortization deferrals and various items subject to reconciliation including hedge losses and deferred property tax.
Regulatory liabilities as of September 30, 2020 and December 31, 2019, respectively, consisted of:
September 30,December 31,
As of20202019
(Millions)
Energy efficiency portfolio standard$72 $72 
Gas supply charge and deferred natural gas cost11 
Pension and other post-retirement benefits cost deferrals69 80 
Carrying costs on deferred income tax bonus depreciation32 49 
Carrying costs on deferred income tax - Mixed Services 263(a)11 15 
2017 Tax Act1,550 1,548 
Revenue decoupling mechanism10 17 
Accrued removal obligations1,181 1,173 
Asset sale gain account10 10 
Economic development27 27 
Positive benefit adjustment35 37 
Theoretical reserve flow thru impact10 14 
Deferred property tax52 17 
Net plant reconciliation23 23 
Debt rate reconciliation83 67 
Rate refund – FERC ROE proceeding33 32 
Transmission congestion contracts24 23 
Merger-related rate credits14 16 
Accumulated deferred investment tax credits26 13 
Asset retirement obligation16 14 
Earning sharing provisions26 28 
Middletown/Norwalk local transmission network service collections18 18 
Low income programs29 33 
Non-firm margin sharing credits15 16 
New York 2018 winter storm settlement11 11 
Other175 159 
Total regulatory liabilities3,556 3,523 
Less: current portion214 242 
Total non-current regulatory liabilities$3,342 $3,281 
“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.
"Gas supply charge and deferred natural gas cost" reflects the actual costs of purchasing, transporting and storing of natural gas. Gas supply reconciliation is determined by comparing actual gas supply expenses to the monthly gas cost recoveries in rates. Prior rate year balances are collected/ returned to customers beginning the next calendar year.
“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.
“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. A portion of this balance is amortized
through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016.
"Carrying costs on deferred income tax - Mixed Services 263(a)" represent the carrying costs benefit of increased accumulated deferred income taxes created by Section 263 (a) IRC. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016.
“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.
"Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales.
“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 customers. The amortization period for the majority of the balance will be determined in future proceedings.
“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 customers. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016.
“Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016.
“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. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016.
"Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided for in rates.
"Net plant reconciliation" represents the reconciliation of the actual electric and gas net plant and book depreciation to the targets set forth in the Joint Proposal.
"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.
"Rate refund - FERC ROE proceeding" represents the reserve associated with the FERC proceeding around the base return on equity (ROE) reflected in ISO New England, Inc.’s (ISO-NE) open access transmission tariff (OATT). See Note 8 for more details.
"Transmission congestion contracts" represents deferral of Nine Mile 2 Nuclear Plant transmission congestion contract at RGE.
“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During the three and nine months ended September 30, 2020 and 2019, respectively, $1 million and $2 million of rate credits were applied against customer bills.
"Asset retirement obligation" 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.
"Earning sharing provisions" represents the annual earnings over the earning sharing threshold.
"Middletown/Norwalk local transmission network service collections" represents allowance for funds used during construction of the Middletown/Norwalk transmission line, which is being amortized over the useful life of the project.
“Low income programs” represent various hardship and payment plan programs approved for recovery.
"New York 2018 winter storm settlement" represents the settlement amount with the NYSPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms.
“Other” includes cost of removal being amortized through rates and various items subject to reconciliation including rate change levelization.
v3.20.2
Fair Value of Financial Instruments and Fair Value Measurements
9 Months Ended
Sep. 30, 2020
Fair Value Disclosures [Abstract]  
Fair Value of Financial Instruments and Fair Value Measurements 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 equity and other investments consist of Rabbi Trusts for deferred compensation plans and a supplemental retirement benefit life insurance trust. The Rabbi Trusts primarily include equity securities and money market funds. We measure the fair value of our Rabbi Trust portfolio using observable, unadjusted quoted market prices in active markets for identical assets and include the measurements in Level 1. We measure the fair value of the supplemental retirement benefit life insurance trust based on quoted prices in the active markets for the various funds within which the assets are held and include the measurement in Level 2.
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 measurements 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 fair value Level 1. 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 fair value Level 2. 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 fair value Level 3. 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 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 $5 million and $6 million as of September 30, 2020 and December 31, 2019, respectively, and is included in "Other Assets" on our condensed consolidated balance sheets.
The financial instruments measured at fair value as of September 30, 2020 and December 31, 2019, respectively, consisted of:
As of September 30, 2020Level 1Level 2Level 3NettingTotal
(Millions)     
Equity investments with readily determinable fair values$41 $12 $ $ $53 
Derivative assets
Derivative financial instruments - power$$19 $118 $(67)$78 
Derivative financial instruments - gas26 29 (37)22 
Contracts for differences — — — 
Derivative financial instruments – other— — — 
Total$12 $47 $149 $(104)$104 
Derivative liabilities
Derivative financial instruments - power$(17)$(31)$(34)$77 $(5)
Derivative financial instruments - gas— (5)(4)(1)
Contracts for differences — — (92)— (92)
Derivative financial instruments – other— — (2)— (2)
Total$(17)$(36)$(132)$85 $(100)
As of December 31, 2019Level 1Level 2Level 3NettingTotal
(Millions)     
Equity investments with readily determinable fair values$38 $13 $ $ $51 
Derivative assets
Derivative financial instruments - power$$23 $120 $(54)$93 
Derivative financial instruments - gas— 40 31 (71)— 
Contracts for differences— — — 
Total$4 $63 $153 $(125)$95 
Derivative liabilities
Derivative financial instruments - power$(28)$(43)$(29)$92 $(8)
Derivative financial instruments - gas(4)(26)(5)33 (2)
Contracts for differences— — (94)— (94)
Derivative financial instruments - other— (1)— — (1)
Total$(32)$(70)$(128)$125 $(105)
The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and nine months ended September 30, 2020 and 2019, respectively, is as follows:
Three Months Ended September 30,Nine Months Ended September 30,
(Millions)2020201920202019
Fair Value Beginning of Period,$16 $(32)$25 $(15)
Gains recognized in operating revenues38 10 42 
(Losses) recognized in operating revenues— (22)(4)(5)
Total gains recognized in operating revenues16 37 
Gains recognized in OCI— 12 — 
(Losses) recognized in OCI(1)— (7)(2)
Total gains (losses) recognized in OCI(1)12 (5)(2)
Net change recognized in regulatory assets and liabilities
Purchases(1)— — (23)
Settlements(1)10 (9)
Transfers out of Level 3 (a)(1)— (2)— 
Fair Value as of September 30,$17 $$17 $
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
$$16 $$37 
(a) Transfers out of Level 3 were the result of increased observability of market data.
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 September 30, 2020    
InstrumentsInstrument DescriptionValuation TechniqueValuation
Inputs
IndexAvg.Max.Min.
Fixed price power and gas swaps with delivery period > two yearsTransactions with delivery periods exceeding two yearsTransactions are valued against forward market prices on a discounted basisObservable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar productsNYMEX ($/MMBtu)$2.51 $3.45 $1.48 
AECO ($/MMBtu)$1.43 $3.23 $(0.17)
Ameren ($/MWh)$26.03 $40.53 $14.73 
COB ($/MWh)$33.12 $95.00 $8.20 
ComEd ($/MWh)$24.01 $39.26 $12.65 
ERCOT N hub ($/MWh)$32.30 $196.95 $11.25 
ERCOT S hub ($/MWh)$32.66 $203.37 $11.41 
Indiana hub ($/MWh)$28.16 $43.58 $16.36 
Mid C ($/MWh)$29.58 $95.00 $4.00 
Minn hub ($/MWh)$22.75 $37.78 $11.52 
NoIL hub ($/MWh)$23.92 $39.01 $12.70 
PJM W hub ($/MWh)$28.41 $59.53 $14.28 
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 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 extends 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 InputSeptember 30, 2020
Risk of non-performance
0.59% - 0.64%
Discount rate
0.29% - 0.49%
Forward pricing ($ per KW-month)
$2.00 - $5.30
Fair Value of Debt
As of September 30, 2020 and December 31, 2019, 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 $9,216 million and $8,168 million as of September 30, 2020 and December 31, 2019, 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.
v3.20.2
Derivative Instruments and Hedging
9 Months Ended
Sep. 30, 2020
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 September 30, 2020 and December 31, 2019, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:
As of September 30, 2020Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)    
Not designated as hedging instruments    
Derivative assets$11 $$$
Derivative liabilities(7)(1)(26)(83)
(19)(82)
Designated as hedging instruments
Derivative assets— — — — 
Derivative liabilities— — (1)— 
— — (1)— 
Total derivatives before offset of cash collateral(20)(82)
Cash collateral receivable — — 
Total derivatives as presented in the balance sheet
$$$(14)$(79)
As of December 31, 2019Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)    
Not designated as hedging instruments    
Derivative assets$$$$
Derivative liabilities(1)(2)(39)(86)
— (38)(84)
Designated as hedging instruments
Derivative assets— — — — 
Derivative liabilities— — (1)(1)
— — (1)(1)
Total derivatives before offset of cash collateral— (39)(85)
Cash collateral receivable— — 27 
Total derivatives as presented in the balance sheet
$— $$(12)$(84)
The net notional volumes of the outstanding derivative instruments associated with Networks activities as of September 30, 2020 and December 31, 2019, respectively, consisted of:
 September 30,December 31,
As of20202019
(Millions)  
Wholesale electricity purchase contracts (MWh)5.1 5.1 
Natural gas purchase contracts (Dth)8.8 8.5 
Fleet fuel purchase contracts (Gallons)2.4 2.2 
Derivatives not designated as hedging instruments
NYSEG and RG&E have an electric commodity charge that passes costs for the market price of electricity through rates. 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 September 30, 2020 and December 31, 2019 and amounts reclassified from regulatory assets and liabilities into income for the three and nine months ended September 30, 2020 and 2019 are as follows:
(Millions)Loss or Gain Recognized in Regulatory Assets/LiabilitiesLocation of Loss Reclassified from Regulatory Assets/Liabilities into IncomeLoss Reclassified from Regulatory Assets/Liabilities into Income
As ofThree Months Ended September 30,Nine Months Ended September 30,
September 30, 2020ElectricityNatural Gas2020 ElectricityNatural GasElectricityNatural Gas
Regulatory assets$$— Purchased power, natural gas and fuel used$$— $41 $
Regulatory liabilities$— $(4)
December 31, 20192019 
Regulatory assets$24 $Purchased power, natural gas and fuel used$$— $16 $— 
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 September 30, 2020, 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 $90 million, a gross derivative liability of $92 million ($89 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, 2019, UI had 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 $92 million, a gross derivative liability of $94 million ($92 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 nine months ended September 30, 2020 and 2019, respectively, were as follows:
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(Millions)    
Derivative assets$— $— $— $(3)
Derivative liabilities$$$$
Certain foreign currency exchange contracts are not designated as hedging instruments. For both the three and nine months ended September 30, 2020, we recorded a gain of $3 million related to our foreign currency contracts not designated as hedging instruments, included in "Other income" in our condensed consolidated statements of income. No amounts were recorded for both the three and nine months ended September 30, 2019.
Derivatives designated as hedging instruments
The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,(Loss) Recognized in OCI on Derivatives (a)Location of Loss (Gain) Reclassified from Accumulated OCI into IncomeLoss (Gain) Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Interest rate contracts$— Interest expense$$86 
Commodity contracts(1)Purchased power, natural gas and fuel used— 259 
Foreign currency exchange contracts
— — 
Total$(1)$1 
2019
Interest rate contracts$— Interest expense$$72 
Commodity contracts— Purchased power, natural gas and fuel used(1)279 
Foreign currency exchange contracts
(5)— 
Total$(5)$ 
Nine Months Ended September 30,(Loss) Gain Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss (Gain) Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Interest rate contracts$— Interest expense$$251 
Commodity contracts(2)Purchased power, natural gas and fuel used999 
Foreign currency exchange contracts
(2)— 
Total$(4)$4 
2019
Interest rate contracts$— Interest expense$$226 
Commodity contracts— Purchased power, natural gas and fuel used(1)1,101 
Foreign currency exchange contracts
(4)— 
Total$(4)$4 
(a) Changes in accumulated OCI are reported on a pre-tax basis.
The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $52 million and $55 million as of September 30, 2020 and December 31, 2019, respectively. We recorded $1 million and $3 million in net derivative losses related to discontinued cash flow hedges for the three and nine months ended September 30, 2020, respectively and $1 million and $5 million for the three and nine months ended September 30, 2019, respectively. We will amortize approximately $1 million of discontinued cash flow hedges for the remainder of 2020.
Unrealized losses of $1 million on hedge derivatives are reported in OCI because the forecasted transactions are considered to be probable as of September 30, 2020. 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 12 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 September 30, 2020 and December 31, 2019, respectively, consisted of:
September 30,December 31,
As of20202019
(MWh/Dth in millions)  
Wholesale electricity purchase contracts
Wholesale electricity sales contracts
Natural gas and other fuel purchase contracts29 29 
Financial power contracts12 10 
Basis swaps – purchases40 42 
Basis swaps – sales— 
The fair values of derivative contracts associated with Renewables activities as of September 30, 2020 and December 31, 2019, respectively, consisted of:
September 30,December 31,
As of20202019
(Millions)  
Wholesale electricity purchase contracts$$10 
Wholesale electricity sales contracts
Natural gas and other fuel purchase contracts(2)
Financial power contracts62 73 
Basis swaps – purchases12 — 
Total$89 $85 
The tables below present Renewables' derivative positions as of September 30, 2020 and December 31, 2019, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:
As of September 30, 2020Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets$49 $111 $$
Derivative liabilities(26)(13)(3)(2)
23 98 (2)— 
Designated as hedging instruments
Derivative assets20 
Derivative liabilities(7)(15)(5)(3)
(2)(3)(2)
Total derivatives before offset of cash collateral21 103 (5)(2)
Cash collateral payable(8)(20)— — 
Total derivatives as presented in the balance sheet $13 $83 $(5)$(2)
As of December 31, 2019Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets$23 $110 $42 $13 
Derivative liabilities(1)(7)(48)(18)
22 103 (6)(5)
Designated as hedging instruments
Derivative assets— 18 
Derivative liabilities— (9)(13)(6)
— (8)(2)
Total derivatives before offset of cash collateral22 112 (14)(7)
Cash collateral (payable) receivable(11)(30)
Total derivatives as presented in the balance sheet$11 $82 $(7)$(1)
Derivatives not designated as hedging instruments
The effects of trading and non-trading derivatives associated with Renewables activities for the three and nine months ended September 30, 2020, consisted of:
Three Months Ended Nine Months Ended
September 30, 2020September 30, 2020
TradingNon-tradingTotal amount per income statementTradingNon-tradingTotal amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts$$— $$— 
Wholesale electricity sales contracts(7)(11)(1)
Financial power contracts(12)
Financial and natural gas contracts— (8)— (13)
Total (loss) gain included in operating revenues
$— $(31)$1,470 $$(7)$4,651 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts$— $$— $(2)
Wholesale electricity sales contracts— — — 
Financial and natural gas contracts— 16 — 19 
Total gain included in purchased power, natural gas and fuel used$— $26 $259 $— $17 $999 
Total (Loss) Gain $— $(5)$$10 
The effects of trading and non-trading derivatives associated with Renewables activities for the three and nine months ended September 30, 2019, consisted of:
Three Months Ended Nine Months Ended
September 30, 2019September 30, 2019
TradingNon-tradingTotal amount per income statementTradingNon-tradingTotal amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts$(1)$— $(2)$— 
Wholesale electricity sales contracts— 42 37 
Financial power contracts— 13 — 22 
Financial and natural gas contracts— (1)
Total (loss) gain included in operating revenues$(1)$56 $1,487 $(1)$60 $4,729 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts$— $(19)$— $(2)
Financial power contracts— — — (2)
Financial and natural gas contracts— — 10 
Total (loss) gain included in purchased power, natural gas and fuel used
$— $(13)$279 $— $$1,101 
Total (Loss) Gain $(1)$43 $(1)$66 
During September 2019, Renewables liquidated a portion of one of its wholesale electricity sales contracts and recorded a gain of $43 million for the three and nine months ended September 30, 2019.
Derivatives designated as hedging instruments
The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,(Loss) Gain Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Commodity contracts$(17)Operating revenues$$1,470 
2019
Commodity contracts$13 Operating revenues$$1,487 
Nine Months Ended September 30,(Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Commodity contracts$(9)Operating revenues$$4,651 
2019
Commodity contracts$(2)Operating revenues$$4,729 
(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 $4 million of losses included in accumulated OCI at September 30, 2020, are 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 nine months ended September 30, 2020 and 2019.
(c) Interest rate contracts
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.
On January 31, 2020, AVANGRID entered into two treasury locks, with a total notional amount of $600 million, to hedge the issuance of forecasted fixed rate debt. The treasury locks were designated and qualified as cash flow hedges and were settled upon the second quarter debt issuance described in Note 15. The $27 million loss on the treasury locks is reported as a component of accumulated OCI and is being reclassified into earnings during the periods in which the related interest expense of the forecasted debt is incurred.
The net loss in accumulated OCI related to previously settled interest rate contracts is $59 million and $38 million as of September 30, 2020 and December 31, 2019, respectively. We amortized into income $2 million and $5 million of the loss related to the settled interest rate contracts for the three and nine months ended September 30, 2020, respectively, and $1 million for the three and nine months ended September 30, 2019. We will amortize approximately $2 million of the net loss on the interest rate contracts for the remainder of 2020.
The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,Gain (Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Interest rate contracts$— Interest expense$$86 
2019
Interest rate contracts$— Interest expense$$72 
Nine Months Ended September 30,(Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Interest rate contracts$(27)Interest expense$$251 
2019
Interest rate contracts$(24)Interest expense$$226 
(a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods.
(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 September 30, 2020, UI would have had to post an aggregate of approximately $13 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 $23 million and $21 million as of September 30, 2020 and December 31, 2019, 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 September 30, 2020 is $9 million, for which we have posted collateral.
v3.20.2
Contingencies
9 Months Ended
Sep. 30, 2020
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 $26 million and $7 million, respectively, as of September 30, 2020, which has not changed since December 31, 2019, 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). Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019 and replied to the initial briefs on March 8, 2019.
On November 21, 2019, the FERC issued rulings on two complaints challenging the base return on equity for Midcontinent Independent System Operator, or MISO transmission owners. These rulings established a new zone of reasonableness based on equal weighting of the DCF and capital-asset pricing model for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing on this decision, which was granted. On May 21, 2020, FERC issued a ruling, which, among other things, adjusted the methodology to determine the MISO transmission owners’ ROE, resulting in an increase in ROE from 9.88% to 10.02% by utilizing the risk premium model in addition to the DCF model and capital-asset pricing model under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. We cannot predict the outcome of these proceedings, including the potential impact the MISO transmission owners' ROE proceeding may have in establishing a precedent for our pending four Complaints.
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 no 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 Action Regarding LDC Gas Transportation Service on Algonquin Gas Transmission
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 and, on October 18, 2019, filed a brief in support of appeal. On January 2, 2020, the Company and Eversource filed a joint motion in opposition and on January 23, 2020, the plaintiffs filed a reply brief. On April 9, 2020, the U.S. Court of Appeals for the First Circuit canceled oral arguments of the appeal and ordered the case to be decided on the briefs without oral argument. On September 9, 2020, the First Circuit denied the appeal and affirmed the District Court’s dismissal of PNE’s complaint.
Gas Storage Indemnification Claims
On May 1, 2018, ARHI closed a transaction to sell our gas storage business to Amphora Gas Storage USA, LLC. On October 30, 2019, ARHI received notice of a claim for indemnification from Amphora Gas Storage USA, LLC under the purchase agreement with respect to such sale in the amount of approximately $20 million related to, among other things, certain alleged violations of occupational, health and safety requirements, the condition and sufficiency of assets and a third party intellectual property infringement claim. Pursuant to the terms of the purchase agreement, the aggregate amount for which ARHI may be responsible to indemnify Amphora Gas Storage USA, LLC for all claims arising under the purchase agreement, other than those related to certain fundamental representations, tax matters and claims involving fraud, shall not exceed 15% of the purchase price, or approximately $10 million. ARHI has disputed this claim for indemnification. We cannot predict the outcome of this matter.
Guarantee Commitments to Third Parties
As of September 30, 2020, we had approximately $449 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 September 30, 2020, neither we nor our subsidiaries have any liabilities recorded for these instruments.
v3.20.2
Environmental Liabilities
9 Months Ended
Sep. 30, 2020
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-six waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-six sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; five sites are included in Maine’s Uncontrolled Sites Program; one site is included in the Brownfield Cleanup 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, six of the twenty-six 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 $6 million related to twelve of the twenty-six sites. We have paid remediation costs related to the remaining fourteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $9 million related to another twelve sites where we believe it is probable that we will incur remediation
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 $13 million to $23 million as of September 30, 2020. 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). Six 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 and one site is pending application into the Brownfield Cleanup 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 $181 million to $378 million as of September 30, 2020. 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 September 30, 2020 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 September 30, 2020 and December 31, 2019, the liability associated with our MGP sites in Connecticut was $96 million and $97 million, respectively, 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.
Our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $344 million and $349 million as of September 30, 2020 and December 31, 2019, 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 2058.
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.
English Station
In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then owners of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut related to environmental remediation at the English Station site. This proceeding was 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 related to the English Station site. 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. 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. The plaintiffs have appealed the court's decision to strike. 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. 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 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 September 30, 2020 and December 31, 2019, the amount reserved for this matter was $17 million and $16 million, respectively. We cannot predict the outcome of this matter.
On April 24, 2020, ACV Environmental Services Company (ACV) filed a lawsuit in Connecticut Superior Court against UI arising out of a contract dispute for services rendered by ACV in the demolition of the Station B at the English Station site. The complaint seeks damages in the amount of $5 million on claims of breach of contract, breach of the covenant of good faith and fair dealing, quantum merit, and unjust enrichment. The claims arise from the alleged non-payment of certain change order requests. We cannot predict the outcome of this matter.
v3.20.2
Post-retirement and Similar Obligations
9 Months Ended
Sep. 30, 2020
Retirement Benefits [Abstract]  
Post-retirement and Similar Obligations Post-retirement and Similar Obligations
We made $34 million and $59 million of pension contributions for the three and nine months ended September 30, 2020, respectively. We expect to make additional contributions of $25 million for the remainder of 2020.
The components of net periodic benefit cost for pension benefits for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(Millions)    
Service cost$12 $10 $35 $30 
Interest cost27 33 81 98 
Expected return on plan assets(50)(48)(150)(144)
Amortization of:
Prior service costs— — — (1)
Actuarial loss31 28 94 85 
Net Periodic Benefit Cost$20 $23 $60 $68 
The components of net periodic benefit cost for postretirement benefits for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of: 
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(Millions)    
Service cost$$$$
Interest cost10 12 
Expected return on plan assets(2)(1)(6)(5)
Amortization of:
Prior service costs(3)(3)(7)(7)
Actuarial loss— — (1)
Net Periodic Benefit Cost$ $1 $ $1 
v3.20.2
Equity
9 Months Ended
Sep. 30, 2020
Equity [Abstract]  
Equity Equity
As of September 30, 2020 and December 31, 2019, we had 485,597 and 485,810 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the three and nine months ended September 30, 2020 we released 0 and 213 shares of common stock held in trust, respectively. During both the three and nine months ended September 30, 2019, we released no shares of common stock held in trust. In October 2020, we released 4,332 shares of common stock held in trust.
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 Iberdrola's relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In May 2020, 42,777 shares were repurchased pursuant to the stock repurchase program. As of September 30, 2020, a total of 303,835 shares have been repurchased in the open market, all of which are included as AVANGRID treasury shares. The total cost of all repurchases, including commissions, was $14 million as of September 30, 2020.
Accumulated Other Comprehensive Loss 
Accumulated Other Comprehensive Loss for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:
As of June 30,Three Months Ended September 30,As of September 30,As of June 30,Three Months Ended September 30,As of September 30,
202020202020201920192019
(Millions)      
Change in revaluation of defined benefit plans
$(12)$— $(12)$(13)$— $(13)
Loss on nonqualified pension plans(7)— (7)(7)— (7)
Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $(3) for 2020 and $2 for 2019
(29)(15)(44)(18)(13)
Reclassification to net income of losses on cash flow hedges, net of income tax expense of $0 for 2020 and $1 for 2019(a)
(60)(51)(71)(66)
(Loss) Gain on derivatives qualifying as cash flow hedges(89)(6)(95)(89)10 (79)
Accumulated Other Comprehensive (Loss) Income
$(108)$(6)$(114)$(109)$10 $(99)
As of December 31,Nine Months Ended September 30,As of September 30,As of December 31,Adoption of new accountingNine Months Ended September 30,As of September 30,
2019202020202018standard20192019
(Millions)      
Change in revaluation of defined benefit plans
$(12)$— $(12)$(11)$(2)$— $(13)
Loss on nonqualified pension plans(7)— (7)(6)— (1)(7)
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(8) for both 2020 and 2019
(13)(31)(44)— (22)(13)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense of $1 for 2020 and $2 for 2019(a)
(63)12 (51)(64)(10)(66)
Loss on derivatives qualifying as cash flow hedges
(76)(19)(95)(55)(10)(14)(79)
Accumulated Other Comprehensive Loss
$(95)$(19)$(114)$(72)$(12)$(15)$(99)
(a)Reclassification is reflected in the operating expenses line item in our condensed consolidated statements of income.
v3.20.2
Earnings Per Share
9 Months Ended
Sep. 30, 2020
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 nine months ended September 30, 2020 and 2019, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculations.
The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(Millions, except for number of shares and per share data)    
Numerator:    
Net income attributable to AVANGRID$87 $150 $415 $477 
Denominator:
Weighted average number of shares outstanding - basic309,491,082 309,491,082 309,496,234 309,491,082 
Weighted average number of shares outstanding - diluted309,550,126 309,517,778 309,554,838 309,512,301 
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic$0.28 $0.48 $1.34 $1.54 
Earnings Per Common Share, Diluted$0.28 $0.48 $1.34 $1.54 
v3.20.2
Segment Information
9 Months Ended
Sep. 30, 2020
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 earnings from changes in the fair value of derivative instruments, accelerated depreciation derived from repowering of wind farms and costs incurred in connection with the COVID-19 pandemic.
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 our condensed consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment.
Segment information as of and for the three and nine months ended September 30, 2020, consisted of:
Three Months Ended September 30, 2020NetworksRenewablesOther (a)AVANGRID Consolidated
(Millions)    
Revenue - external$1,194 $275 $$1,470 
Revenue - intersegment(4)— 
Depreciation and amortization151 104 — 255 
Operating income (loss)160 (2)165 
Earnings (losses) from equity method investments(2)— 
Interest expense, net of capitalization63 (1)24 86 
Income tax expense (benefit)20 (7)15 
Adjusted net income$99 $32 $(31)$100 
Nine Months Ended September 30, 2020NetworksRenewablesOther (a)AVANGRID Consolidated
(Millions)    
Revenue - external$3,775 $875 $$4,651 
Revenue - intersegment(5)— 
Depreciation and amortization446 301 748 
Operating income617 24 647 
Earnings (losses) from equity method investments(11)— (3)
Interest expense, net of capitalization199 (1)53 251 
Income tax expense (benefit)75 (53)(1)21 
Adjusted net income379 108 (53)434 
Capital expenditures1,312 648 — 1,960 
As of September 30, 2020
Property, plant and equipment16,640 9,782 10 26,432 
Equity method investments138 530 — 668 
Total assets$24,178 $12,694 $(1,232)$35,640 
(a) Includes Corporate and intersegment eliminations.
Segment information for the three and nine months ended September 30, 2019 and as of December 31, 2019, consisted of:
Three Months Ended September 30, 2019NetworksRenewablesOther (a)AVANGRID Consolidated
(Millions)    
Revenue - external$1,139 $347 $$1,487 
Revenue - intersegment— (1)— 
Depreciation and amortization138 98 237 
Operating income182 53 239 
Earnings (losses) from equity method investments(4)— (1)
Interest expense, net of capitalization66 (1)72 
Income tax expense28 33 
Adjusted net income$89 $46 $(12)$123 
Nine Months Ended September 30, 2019NetworksRenewablesOther (a)AVANGRID
Consolidated
(Millions)    
Revenue - external$3,831 $896 $$4,729 
Revenue - intersegment— (6)— 
Depreciation and amortization407 273 681 
Operating income668 115 787 
Earnings (losses) from equity method investments(7)— 
Interest expense, net of capitalization201 19 226 
Income tax expense (benefit)117 (15)103 
Adjusted net income355 115 (28)442 
Capital expenditures1,086 959 — 2,045 
As of December 31, 2019    
Property, plant and equipment15,840 9,368 10 25,218 
Equity method investments139 506 — 645 
Total assets$23,250 $13,163 $(1,997)$34,416 
(a) Includes Corporate and intersegment eliminations.
Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three and nine months ended September 30, 2020 and 2019, respectively, is as follows:
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(Millions)    
Adjusted Net Income Attributable to Avangrid, Inc.$100 $123 $434 $442 
Adjustments:
Mark-to-market earnings - Renewables (1)(7)42 66 
Restructuring charges (2)(1)(2)(5)(4)
Accelerated depreciation from repowering (3)(3)(5)(9)(15)
Impact of COVID-19 (4)(8)— (21)— 
Income tax impact of adjustments(9)(12)
Net Income Attributable to Avangrid, Inc.$87 $150 $415 $477 
(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.
(2)Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth.
(3)Represents the amount of accelerated depreciation derived from repowering of wind farms in Renewables.
(4)Represents costs incurred in connection with the COVID-19 pandemic.
v3.20.2
Related Party Transactions
9 Months Ended
Sep. 30, 2020
Related Party Transactions [Abstract]  
Related Party Transactions Related Party TransactionsWe 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 nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,20202019
(Millions)Sales ToPurchases FromSales ToPurchases From
Iberdrola Renovables Energía, S.L.$— $(2)$— $(1)
Iberdrola Financiación, S.A.$— $(3)$— $(1)
Iberdrola, S.A.$— $(10)$— $(8)
Vineyard Wind$$— $$— 
Iberdrola Solutions$$— $— $— 
Other$— $(1)$— $(1)
Nine Months Ended September 30,20202019
(Millions)Sales ToPurchases FromSales ToPurchases From
Iberdrola Renovables Energía, S.L.$— $(6)$— $(10)
Iberdrola Financiación, S.A.$— $(5)$— $(2)
Iberdrola, S.A.$— $(31)$— $(28)
Vineyard Wind$$— $11 $— 
Iberdrola Solutions$$— $— $— 
Other$— $(2)$$(2)
In addition to the statements of income items above, we made purchases of turbines for wind farms from Siemens-Gamesa, in which Iberdrola had an 8.1% ownership interest until Iberdrola sold its interest in February 2020. After the sale, the turbine purchases are no longer considered related party transactions. The amounts capitalized for transactions while Siemens-Gamesa was considered a related party were $11 million and $18 million for the periods ended September 30, 2020 and December 31, 2019, respectively.
Related party balances as of September 30, 2020 and December 31, 2019, respectively, consisted of:
As ofSeptember 30, 2020December 31, 2019
(Millions)Owed ByOwed ToOwed ByOwed To
Iberdrola, S.A.$$(32)$$(42)
Iberdrola Renovables Energía, S.L.$— $(6)$— $— 
Iberdrola Financiación, S.A.$— $(4)$— $— 
Vineyard Wind$$— $$— 
Iberdrola Solutions$$(4)$— $— 
Siemens-Gamesa (a)$— $— $— $(18)
Other$$(1)$$(4)
(a) After Iberdrola's sale of its interest of Siemens-Gamesa in February 2020, transactions with Siemens-Gamesa are no longer considered related party.
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.
See Note 19 - Equity Method Investments for more information on Vineyard Wind, LLC (Vineyard Wind).
We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had a notes payable balance of $4 million and $0, respectively, as of September 30, 2020 and December 31, 2019.
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.
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 September 30, 2020 and December 31, 2019, was zero and $150 million, respectively.
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 September 30, 2020 and December 31, 2019, there was no outstanding amount under this credit facility.
v3.20.2
Other Financial Statement Items
9 Months Ended
Sep. 30, 2020
Balance Sheet Related Disclosures [Abstract]  
Other Financial Statement Items Other Financial Statement Items
Accounts receivable and unbilled revenue, net
Accounts receivable and unbilled revenues, net as of September 30, 2020 and December 31, 2019 consisted of:
As of September 30, 2020December 31, 2019
(Millions)
Trade receivables and unbilled revenues$1,115 $1,151 
Allowance for credit losses(94)(69)
Accounts receivable and unbilled revenues, net$1,021 $1,082 
The change in the allowance for credit losses for the three and nine months ended September 30, 2020 and 2019 consisted of:
Three Months Ended September 30,Nine Months Ended September 30,
(Millions)2020201920202019
As of Beginning of Period,$85 $73 $69 $62 
Current period provision19 24 60 71 
Write-off as uncollectible(10)(24)(35)(60)
As of September 30,$94 $73 $94 $73 
The Deferred Payment Arrangements (DPA) receivable balance was $77 million and $65 million at September 30, 2020 and December 31, 2019, respectively. The allowance for credit losses for DPAs at September 30, 2020 and December 31, 2019 was $37 million and $33 million respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three and nine months ended September 30, 2020, was $3 million and $4 million, respectively, and for the three and nine months ended September 30, 2019, $1 million and $3 million, respectively.
Prepayments and other current assets
Included in prepayments and other current assets are $179 million and $123 million of prepaid other taxes as of September 30, 2020 and December 31, 2019, respectively.
Property, plant and equipment and intangible assets
The accumulated depreciation and amortization as of September 30, 2020 and December 31, 2019, respectively, were as follows:
 September 30,December 31,
As of20202019
(Millions)  
Property, plant and equipment  
Accumulated depreciation$9,713 $9,059 
Intangible assets  
Accumulated amortization$315 $305 
Debt
As of September 30, 2020 and December 31, 2019, "Notes Payable" consisted of $999 million and $562 million, respectively, of commercial paper outstanding, presented net of discounts on our condensed consolidated balance sheets.
On April 9, 2020, AGR issued $750 million aggregate principal amount of unsecured notes maturing in 2025 at a fixed interest rate of 3.20%.
On May 1, 2020, NYSEG remarketed $200 million aggregate Pollution Control bonds with maturity dates ranging from 2026 to 2029 at fixed interest rates of 1.40% to 1.61%. The remarketing was a non-cash transaction to reset the interest rates.
On June 29, 2020, we entered into a revolving credit agreement with several lenders (the 2020 Credit Facility), that provides maximum borrowings up to $500 million. We will pay an annual facility fee, which ranges from 15 to 30 basis points, dependent on AVANGRID’s credit rating. As of September 30, 2020, the facility fee is 20 basis points. The 2020 Credit Facility matures on June 28, 2021. We have the right to extend, and the banks are obligated to extend, the commitments and loans outstanding under the facility for one year at a cost of 75 basis points. We may also request an extension of the facility for one year, which the banks may grant at their discretion for a fee that will be determined at the time of the request. As of September 30, 2020, there were no borrowings outstanding under this credit facility.
On September 1, 2020, BGC issued $25 million aggregate principal amount of unsecured notes maturing in 2050 at a fixed interest rate of 3.68%.
On September 25, 2020, NYSEG issued $200 million aggregate principal amount of unsecured notes maturing in 2030 at a fixed interest rate of 1.95%.
Disposition
On July 24, 2020, Renewables reached an agreement to transfer 85% ownership in one South Dakota wind farm for a purchase price of $236 million, subject to closing adjustments as applicable. The transaction, which is subject to the satisfaction of customary closing conditions, including FERC approval, is expected to be completed during the fourth quarter of 2020. As of September 30, 2020, the carrying value of the wind farm primarily consisted of $196 million of assets held for sale included in "property, plant and equipment" on our condensed consolidated balance sheet.
v3.20.2
Income Tax Expense
9 Months Ended
Sep. 30, 2020
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 nine months ended September 30, 2020, were 15.6% and 5.1%, respectively. The effective tax rates for the three and nine months ended September 30, 2020 are below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act.
The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2019, were 19.2% and 18.3%, respectively. The effective tax rate for the three months ended September 30, 2019 is below than the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, offset by unfavorable discrete tax adjustments. The effective tax rate for the nine months ended September 30, 2019 is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and favorable discrete tax adjustments.
v3.20.2
Stock-Based Compensation Expense
9 Months Ended
Sep. 30, 2020
Share-based Payment Arrangement [Abstract]  
Stock-Based Compensation Expense Stock-Based Compensation Expense
The Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares).
In June and October 2018, 60,000 and 8,000 RSUs, respectively, were granted to certain officers of AVANGRID. The RSUs vest in full in one installment in June and December 2020, respectively, for each award, provided that the grantee remains continuously employed with AVANGRID through the applicable date. The fair value on the grant date was determined based on a price of $50.40 per share for the June 2018 awards and $47.59 per share for the October 2018 awards. In June 2020, 60,000 RSU's, plus dividend equivalents accrued through the vesting period, were settled for $3 million in cash.
In August 2020, 5,000 RSUs were granted to an officer of AVANGRID. The RSUs vest in three equal installments in 2021, 2022 and 2023, provided that the grantee remains continuously employed with AVANGRID through the applicable vesting dates. The fair value on the grant date was determined based on a price of $48.99 per share.
In February 2020, a total number of 208,268 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance metrics related to the 2016 through 2019 plan and are payable in three equal installments, net of applicable taxes, in 2020, 2021 and 2022. The remaining unvested PSUs were forfeited. In May 2020, 42,777 shares of common stock were issued to settle the first installment payment and 2,605 PSUs were forfeited from the originally approved total number of PSUs.
On March 18, 2020, 167,060 Phantom Shares were granted to certain AVANGRID executives and employees. These awards will vest in three equal installments in 2020, 2021 and 2022 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of AVANGRID’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of AVANGRID’s common stock at each reporting date until the date of settlement. In June 2020, $2 million was paid to settle the first installment under this plan. As of September 30, 2020, the total liability is $2 million, which is included in other current and non-current liabilities.Total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three and nine months ended September 30, 2020 was $1 million and $12 million, respectively, and for the three and nine months ended September 30, 2019 was $0 and $2 million, respectively
v3.20.2
Variable Interest Entities
9 Months Ended
Sep. 30, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Variable Interest Entities Variable Interest Entities
We participate in certain partnership arrangements that qualify as variable interest entities (VIEs). Consolidated VIE's 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 March 2, 2020, we closed on two TEF agreements, receiving $237 million from two tax equity investors related to two wind farms that reached commercial operation. On May 8, 2020, we closed on a TEF agreement, receiving $70 million from the same tax equity investors related to a wind farm that reached commercial operation. The three wind farms are part of a portfolio of companies called Aeolus Wind Power VII, LLC (Aeolus VII). One more wind farm undergoing a repowering will become a part of Aeolus VII once the project is complete and the TEF agreement is finalized. The four wind farms expected to be part of Aeolus VII will total 681 MW of wind power.
The assets and liabilities of the VIEs totaled approximately $1,720 million and $104 million, respectively, at September 30, 2020. As of December 31, 2019, the assets and liabilities of VIEs totaled approximately $806 million and $29 million, respectively. At September 30, 2020 and December 31, 2019, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment.
At September 30, 2020, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot) and Aeolus VII are our consolidated 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 El Cabo, Patriot and Aeolus VII 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.
v3.20.2
Equity Method Investments
9 Months Ended
Sep. 30, 2020
Equity Method Investments and Joint Ventures [Abstract]  
Equity Method Investments Equity Method Investments
Renewables holds a 50% voting interest in Vineyard Wind, a joint venture with Copenhagen Infrastructure Partners (CIP). 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.
In 2019, DEEP selected Vineyard Wind to provide 804 MW of offshore wind through the development of its Park City Wind Project. Pursuant to a joint bidding agreement between Renewables and CIP, CIP held a right to sell all or a portion of its 50% ownership interest to Renewables, subject to certain conditions, however this right expired on September 30, 2020. In October 2020, Vineyard Wind submitted an offshore wind solicitation to NYSERDA to provide 1,200 to 1,300 MW of offshore wind through the development of its Liberty Wind Project. In October 2020, Renewables and CIP entered into an agreement pursuant to which, subject to the satisfaction of certain conditions, CIP may exercise an option to effectuate a series of transactions that include the sale of its ownership interest in the Liberty Wind and Park City Wind Projects to Renewables and the purchase of Renewables’ residual ownership interest in certain lease areas that have not been awarded an offtake agreement as of the date of the exercise of such option by CIP.
Under the provisions of the LLC agreement, Renewables has contributed $157 million to Vineyard Wind. Contributions of $110 million have also been made to enter into a second offshore easement contract and for development costs for the area, which includes the site of the proposed Liberty Wind Project. We expect to provide additional capital contributions.
Vineyard Wind cannot finance its activities without additional support from its owners or third parties so Vineyard Wind is considered a VIE. We are not the primary beneficiary since we do not have a controlling interest in Vineyard Wind, and therefore we do not consolidate Vineyard Wind. Renewables' investment in Vineyard Wind was $261 million and $227 million as of September 30, 2020 and December 31, 2019, respectively.
Networks holds an approximate 20% ownership interest in New York TransCo, LLC (New York TransCo). Through New York TransCo, Networks has formed a partnership with affiliates of 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. In 2019, New York Transco was selected as the developer for Segment B of the AC Transmission Public Policy Project by the NYISO. The total project cost is $600 million, plus interconnection costs. Networks’ contribution as 20% co-owner is $120 million. As of both September 30, 2020 and December 31, 2019, there was no amount receivable from New York TransCo.
v3.20.2
Restructuring and Severance Related Expenses
9 Months Ended
Sep. 30, 2020
Restructuring and Related Activities [Abstract]  
Restructuring and Severance Related Expenses Restructuring and Severance Related Expenses
In 2019, we 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 $0 and $2 million recorded for the three and nine months ended September 30, 2020, respectively, and $1 million and $3 million for the three and nine months ended September 30, 2019, respectively, which are included in "Operations and maintenance" in our condensed consolidated statements of income. "Depreciation and amortization" in our condensed consolidated statements of income includes $1 million and $3 million for the three and nine months ended September 30, 2020, respectively, and $1 for both the three and nine months ended September 30, 2019 for restructuring activities.
As of September 30, 2020, 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:
 Nine Months Ended September 30, 2020
 (Millions)
Beginning Balance $
Restructuring and severance related expenses
Payments(3)
Ending Balance $
v3.20.2
Subsequent Event
9 Months Ended
Sep. 30, 2020
Subsequent Events [Abstract]  
Subsequent Event Subsequent Event
On October 20, 2020, AVANGRID, PNM Resources, Inc., a New Mexico corporation (PNMR) and NM Green Holdings, Inc., a New Mexico corporation and wholly-owned subsidiary of AVANGRID (Merger Sub), entered into an Agreement and Plan of Merger (Merger Agreement), pursuant to which Merger Sub will merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of AVANGRID (Merger). Pursuant to the Merger Agreement, each issued and outstanding share of the common stock of PNMR (PNMR common stock) (other than (i) the issued shares of PNMR common stock that are owned by AVANGRID, Merger Sub, PNMR or any wholly-owned subsidiary of AVANGRID or PNMR, which will be automatically cancelled at the time the Merger is consummated and (ii) shares of PNMR common stock held by a holder who has not voted in favor of, or consented in writing to, the Merger who is entitled to, and who has demanded, payment for fair value of such shares) will be converted, at the time the Merger is consummated, into the right to receive $50.30 in cash (Merger Consideration).
Consummation of the Merger (Closing) is subject to the satisfaction or waiver of certain customary closing conditions, including, without limitation, the approval of the Merger Agreement by the holders of at least a majority of the outstanding shares of PNMR common stock entitled to vote thereon, the absence of any material adverse effect on PNMR, the receipt of certain required regulatory approvals (including approvals from the Public Utility Commission of Texas (PUCT), the New Mexico Public Regulation Commission (NMPRC), the FERC, the Federal Communications Commission (FCC), the Committee on Foreign Investment in the United States (CFIUS), the Nuclear Regulatory Commission (NRC) and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976), the Four Corners Divestiture Agreements (as defined below) being in full force and effect and all applicable regulatory filings associated therewith being made, as well as holders of no more than 15% of the outstanding shares of PNMR common stock validly exercising their dissenters’ rights. The Merger is currently expected to close in the fourth quarter of 2021.
The Merger Agreement also contains representations, warranties and covenants of PNMR, AVANGRID and Merger Sub, which are customary for transactions of this type. In addition, among other things, the Merger Agreement contains a covenant requiring PNMR to, prior to the Closing, enter into agreements (Four Corners Divestiture Agreements) providing for, and to make filings required to, exit from all ownership interests in the Four Corners Power Plant, all with the objective of having the closing date for such exit be no later than December 31, 2024.
In connection with the Merger, Iberdrola, S.A. has provided AVANGRID a commitment letter (Iberdrola Funding Commitment Letter), pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration. To the extent AVANGRID wishes to effect a funding transaction under the Iberdrola Funding Commitment Letter in order to pay the Merger Consideration, the specific terms of any such transaction will be negotiated between Iberdrola and AVANGRID on an arm’s length basis and must be approved by both (i) a majority of the members of the unaffiliated committee of the board of directors of AVANGRID, and (ii) a majority of the board of directors of AVANGRID. Under the terms of such commitment letter, Iberdrola S.A. has agreed to negotiate with AVANGRID the specific terms of any transaction effecting such funding commitment promptly and in good faith, with the objective that such terms shall be commercially reasonable and approved by AVANGRID. AVANGRID’s and Merger Sub’s obligations under the Merger Agreement are not conditioned upon AVANGRID obtaining financing.
The Merger Agreement provides for certain customary termination rights including the right of either party to terminate the Merger Agreement if the Merger is not completed on or before January 20, 2022 (subject to a three-month extension by either party if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). The Merger Agreement further provides that, upon termination of the Merger Agreement under certain specified circumstances (including if AVANGRID terminates the Merger Agreement due to a change in recommendation of the board of directors of PNMR or if PNMR terminates the Merger Agreement to accept a superior proposal (as defined in the Merger Agreement)), PNMR will be required to pay AVANGRID a termination fee of $130 million. In addition, the Merger Agreement provides that (i) if the Merger Agreement is terminated by either party due to a failure of a regulatory closing condition and such failure is the result of AVANGRID’s breach of its regulatory covenants, or (ii) AVANGRID fails to effect the Closing when all closing conditions have been satisfied and it is otherwise obligated to do so under the Merger Agreement, then, in either such case, upon termination of the Merger Agreement, AVANGRID will be required to pay PNMR a termination fee of $184 million as the sole and exclusive remedy. Upon the termination of the Merger Agreement under certain specified circumstances involving a breach of the Merger Agreement, either PNMR or AVANGRID will be required to reimburse the other party’s reasonable and documented out-of-pocket fees and expenses up to $10 million (which amount will be credited toward, and offset against, the payment of any applicable termination fee).
v3.20.2
Significant Accounting Policies and New Accounting Pronouncements (Policies)
9 Months Ended
Sep. 30, 2020
Accounting Policies [Abstract]  
Goodwill
Goodwill
Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed.
Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. If we determine, based on qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass the qualitative assessment, or perform the qualitative assessment but determine that it is more likely than not that its fair value is
less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit.
Accounts receivable and unbilled revenue, net
Accounts receivable and unbilled revenue, net
We record accounts receivable at amounts billed to customers and we record unbilled revenues based on an estimate of energy delivered or services provided to customers. Certain accounts receivable and payable related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services, and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances and they are settled on a net basis. We present receivables and payables subject to such agreements on a net basis on our consolidated balance sheets.
Accounts receivable include amounts due under Deferred Payment Arrangements (DPAs). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies 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 short term.
We establish our allowance for credit losses, including for unbilled revenue, by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. Due to our adoption of Accounting Standards Codification (ASC) 326 effective January 1, 2020, we now also consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the accounts receivable. We write off amounts when we have exhausted reasonable collection efforts.
New accounting pronouncements
Adoption of New Accounting Pronouncements
(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 (ASC 326). 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 collectability 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 ASC 326 to clarify transition and scope requirements, make narrow-scope codification improvements, including in March 2020, and corrections and provide targeted transition relief. We adopted the amendments effective January 1, 2020, including the narrow-scope improvements issued in March 2020, and recorded a cumulative-effect adjustment of $1 million to retained earnings at the beginning of the period of adoption, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures.
(b) Simplifying the test for goodwill impairment
In January 2017, the FASB issued amendments to simplify the test for goodwill impairment, which are required for public entities and certain other entities that have goodwill reported in their financial statements. The amendments simplify the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test, which requires the valuation of assets acquired and liabilities assumed using business combination accounting guidance. Under the new guidance, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; but the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Also, an entity should consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. Certain requirements are eliminated for any reporting unit with a
zero or negative carrying amount; therefore, the same impairment assessment applies to all reporting units. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. As required, we will apply the amendments on a prospective basis.
(c) Changes to the disclosure requirements for fair value measurement and defined benefit plans
In August 2018, the FASB issued amendments related to disclosure requirements for both fair value measurement and defined benefit plans.
The amendments concerning fair value measurement remove, modify and add certain disclosure requirements in order to improve the overall usefulness of the disclosures and reduce unnecessary costs to companies to prepare the disclosures. We adopted the amendments effective January 1, 2020, with no material effect to our disclosures. Certain amendments are to be applied prospectively, and all others are to be applied retrospectively.
The amendments concerning disclosure requirements for defined benefit plans are narrow in scope and apply to all employers that sponsor defined benefit pension or other postretirement plans. The amendments change annual disclosures requirements, including removal of disclosures that are no longer considered cost beneficial, adding certain new relevant disclosures and clarifying specific requirements of disclosures concerning information for defined benefit pension plans. We adopted the amendments effective January 1, 2020, and they will not materially affect the disclosures for our fiscal year ending December 31, 2020. As required, our application will be on a retrospective basis.
(d) Targeted improvements to related party guidance for VIEs
In October 2018, the FASB issued amendments that affect reporting entities that are required to determine whether they should consolidate a legal entity under the consolidation guidance applicable to VIEs. The targeted improvements specifically applicable to public business entities clarify that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures.
(e) Clarifying guidance for certain collaborative arrangements with respect to revenue recognition
The FASB issued amendments in November 2018 to clarify the interaction between the guidance for certain collaborative arrangements and the guidance applicable to ASC 606. A collaborative arrangement is a contractual arrangement under which two or more parties actively participate in a joint operating activity and are exposed to significant risks and rewards that depend on the activity’s commercial success. The targeted improvements clarify that certain transactions between collaborative arrangement participants are within the scope of ASC 606 and thus subject to all of its guidance. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. As required, we retrospectively applied the amendments to the date of our initial application of ASC 606.
Accounting Pronouncements Issued But Not Yet Adopted
The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2019, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.
(a) Simplifying the accounting for income taxes
In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes, eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation; (2) exceptions to accounting for basis differences in equity method investments when there are ownership changes in foreign investments; and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for: (1) franchise taxes that are partially based on income; (2) transactions with a government that result in a step up in the tax basis of goodwill; (3) separate financial statements of legal entities that are not subject to tax; and (4) enacted changes in tax laws in interim periods. The amendments are effective for public business entities for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued, with adoption of all amendments in the same period. Application is on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment aspect. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows.
(b) Facilitation of the effects of reference rate reform on financial reporting
In March 2020, the FASB issued amendments to provide temporary optional guidance to entities to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments respond to concerns about structural risks of interbank offered rates, and particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR). The guidance is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform, around the end of 2021. The guidance applies to contracts that have modified terms that affect, or have the potential to affect, the amount or timing of contractual cash flows resulting from the discontinuance of the reference rate reform. The amendments are effective for all entities as of March 12, 2020, through December 31, 2022, although the FASB has indicated it will monitor developments in the marketplace and consider whether developments warrant an extension. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows.
v3.20.2
Revenue (Tables)
9 Months Ended
Sep. 30, 2020
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 nine months ended September 30, 2020 and 2019 are as follows:
 Three Months Ended September 30, 2020Nine Months Ended September 30, 2020
 NetworksRenewablesOther (b)TotalNetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity
$984 $— $— $984 $2,701 $— $— $2,701 
Regulated operations – natural gas
166 — — 166 910 — — 910 
Nonregulated operations – wind
— 200 — 200 — 639 — 639 
Nonregulated operations – solar
— — — 16 — 16 
Nonregulated operations – thermal
— 13 — 13 — 27 — 27 
Other(a)12 28 (4)36 38 75 (4)109 
Revenue from contracts with customers
1,162 247 (4)1,405 3,649 757 (4)4,402 
Leasing revenue— — — — 
Derivative revenue — 25 — 25 — 111 — 111 
Alternative revenue programs
24 — — 24 109 — — 109 
Other revenue14 16 — 24 
Total operating revenues
$1,197 $276 $(3)$1,470 $3,779 $876 $(4)$4,651 
Three Months Ended September 30, 2019Nine Months Ended September 30, 2019
NetworksRenewablesOther (b)TotalNetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity
$922 $— $— $922 $2,637 $— $— $2,637 
Regulated operations – natural gas
179 — — 179 1,053 — — 1,053 
Nonregulated operations – wind
— 218 — 218 — 621 — 621 
Nonregulated operations – solar
— — — 22 — 22 
Nonregulated operations – thermal
— — — 21 — 21 
Other(a)16 23 — 39 71 40 (4)107 
Revenue from contracts with customers
1,117 255  1,372 3,761 704 (4)4,461 
Leasing revenue— — — — 
Derivative revenue — 84 — 84 — 173 — 173 
Alternative revenue programs
13 — — 13 48 — — 48 
Other revenue— 17 23 19 — 42 
Total operating revenues
$1,140 $347 $ $1,487 $3,837 $896 $(4)$4,729 
(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 and intersegment eliminations.
Schedule of Aggregate Transaction Price Allocations
As of September 30, 2020, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:
As of September 30, 202020212022202320242025ThereafterTotal
(Millions)       
Revenue expected to be recognized on multiyear retail energy sales contracts in place
$$$$$— $— $
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
39 23 15 12 11 75 175 
Revenue expected to be recognized on multiyear renewable energy credit sale contracts
27 18 66 
Total operating revenues$67 $42 $25 $17 $14 $80 $245 
v3.20.2
Regulatory Assets and Liabilities (Tables)
9 Months Ended
Sep. 30, 2020
Regulated Operations [Abstract]  
Schedule of Delivery Rate Increases The below table provides a summary of the proposed delivery rate increases and delivery rate percentages, including rate levelization and excluding energy efficiency, which is a pass-through, for all four businesses:
Year 1Year 2Year 3
Rate IncreaseDelivery Rate %Rate IncreaseDelivery Rate %Rate IncreaseDelivery Rate %
Utility(Millions)Increase(Millions)Increase(Millions)Increase
NYSEG Electric$34.7 4.6 %$71.51 9.1 %$79.4 9.1 %
NYSEG Gas$— — %$1.58 0.8 %$3.3 1.6 %
RG&E Electric$10.7 2.4 %$22.92 5.2 %$25.4 5.2 %
RG&E Gas$— — %$— — %$2.4 1.3 %
Schedule of Current and Non-Current Regulatory Assets
Regulatory assets as of September 30, 2020 and December 31, 2019, respectively, consisted of:
September 30,December 31,
As of20202019
(Millions)
Pension and other post-retirement benefits cost deferrals$101 $125 
Pension and other post-retirement benefits963 1,061 
Storm costs418 272 
Rate adjustment mechanism 16 79 
Revenue decoupling mechanism56 19 
Transmission revenue reconciliation mechanism
Contracts for differences90 92 
Hardship programs26 29 
Plant decommissioning— 
Deferred purchased gas14 25 
Deferred transmission expense14 11 
Environmental remediation costs278 277 
Debt premium88 97 
Unamortized losses on reacquired debt27 29 
Unfunded future income taxes408 399 
Federal tax depreciation normalization adjustment149 153 
Asset retirement obligation21 17 
Deferred meter replacement costs25 27 
COVID-19 cost recovery2
Other138 139 
Total regulatory assets2,843 2,861 
Less: current portion252 294 
Total non-current regulatory assets$2,591 $2,567 
Schedule of Current and Non-Current Regulatory Liabilities
Regulatory liabilities as of September 30, 2020 and December 31, 2019, respectively, consisted of:
September 30,December 31,
As of20202019
(Millions)
Energy efficiency portfolio standard$72 $72 
Gas supply charge and deferred natural gas cost11 
Pension and other post-retirement benefits cost deferrals69 80 
Carrying costs on deferred income tax bonus depreciation32 49 
Carrying costs on deferred income tax - Mixed Services 263(a)11 15 
2017 Tax Act1,550 1,548 
Revenue decoupling mechanism10 17 
Accrued removal obligations1,181 1,173 
Asset sale gain account10 10 
Economic development27 27 
Positive benefit adjustment35 37 
Theoretical reserve flow thru impact10 14 
Deferred property tax52 17 
Net plant reconciliation23 23 
Debt rate reconciliation83 67 
Rate refund – FERC ROE proceeding33 32 
Transmission congestion contracts24 23 
Merger-related rate credits14 16 
Accumulated deferred investment tax credits26 13 
Asset retirement obligation16 14 
Earning sharing provisions26 28 
Middletown/Norwalk local transmission network service collections18 18 
Low income programs29 33 
Non-firm margin sharing credits15 16 
New York 2018 winter storm settlement11 11 
Other175 159 
Total regulatory liabilities3,556 3,523 
Less: current portion214 242 
Total non-current regulatory liabilities$3,342 $3,281 
v3.20.2
Fair Value of Financial Instruments and Fair Value Measurements (Tables)
9 Months Ended
Sep. 30, 2020
Fair Value Disclosures [Abstract]  
Schedule of Fair Value Measurements
The financial instruments measured at fair value as of September 30, 2020 and December 31, 2019, respectively, consisted of:
As of September 30, 2020Level 1Level 2Level 3NettingTotal
(Millions)     
Equity investments with readily determinable fair values$41 $12 $ $ $53 
Derivative assets
Derivative financial instruments - power$$19 $118 $(67)$78 
Derivative financial instruments - gas26 29 (37)22 
Contracts for differences — — — 
Derivative financial instruments – other— — — 
Total$12 $47 $149 $(104)$104 
Derivative liabilities
Derivative financial instruments - power$(17)$(31)$(34)$77 $(5)
Derivative financial instruments - gas— (5)(4)(1)
Contracts for differences — — (92)— (92)
Derivative financial instruments – other— — (2)— (2)
Total$(17)$(36)$(132)$85 $(100)
As of December 31, 2019Level 1Level 2Level 3NettingTotal
(Millions)     
Equity investments with readily determinable fair values$38 $13 $ $ $51 
Derivative assets
Derivative financial instruments - power$$23 $120 $(54)$93 
Derivative financial instruments - gas— 40 31 (71)— 
Contracts for differences— — — 
Total$4 $63 $153 $(125)$95 
Derivative liabilities
Derivative financial instruments - power$(28)$(43)$(29)$92 $(8)
Derivative financial instruments - gas(4)(26)(5)33 (2)
Contracts for differences— — (94)— (94)
Derivative financial instruments - other— (1)— — (1)
Total$(32)$(70)$(128)$125 $(105)
Schedule of Fair Value, Financial instrument Based on Level 3 Reconciliation
The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and nine months ended September 30, 2020 and 2019, respectively, is as follows:
Three Months Ended September 30,Nine Months Ended September 30,
(Millions)2020201920202019
Fair Value Beginning of Period,$16 $(32)$25 $(15)
Gains recognized in operating revenues38 10 42 
(Losses) recognized in operating revenues— (22)(4)(5)
Total gains recognized in operating revenues16 37 
Gains recognized in OCI— 12 — 
(Losses) recognized in OCI(1)— (7)(2)
Total gains (losses) recognized in OCI(1)12 (5)(2)
Net change recognized in regulatory assets and liabilities
Purchases(1)— — (23)
Settlements(1)10 (9)
Transfers out of Level 3 (a)(1)— (2)— 
Fair Value as of September 30,$17 $$17 $
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
$$16 $$37 
(a) Transfers out of Level 3 were the result of increased observability of market data.
Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows:
Range at
Unobservable InputSeptember 30, 2020
Risk of non-performance
0.59% - 0.64%
Discount rate
0.29% - 0.49%
Forward pricing ($ per KW-month)
$2.00 - $5.30
Schedule of Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques
The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives.
As of September 30, 2020    
InstrumentsInstrument DescriptionValuation TechniqueValuation
Inputs
IndexAvg.Max.Min.
Fixed price power and gas swaps with delivery period > two yearsTransactions with delivery periods exceeding two yearsTransactions are valued against forward market prices on a discounted basisObservable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar productsNYMEX ($/MMBtu)$2.51 $3.45 $1.48 
AECO ($/MMBtu)$1.43 $3.23 $(0.17)
Ameren ($/MWh)$26.03 $40.53 $14.73 
COB ($/MWh)$33.12 $95.00 $8.20 
ComEd ($/MWh)$24.01 $39.26 $12.65 
ERCOT N hub ($/MWh)$32.30 $196.95 $11.25 
ERCOT S hub ($/MWh)$32.66 $203.37 $11.41 
Indiana hub ($/MWh)$28.16 $43.58 $16.36 
Mid C ($/MWh)$29.58 $95.00 $4.00 
Minn hub ($/MWh)$22.75 $37.78 $11.52 
NoIL hub ($/MWh)$23.92 $39.01 $12.70 
PJM W hub ($/MWh)$28.41 $59.53 $14.28 
v3.20.2
Derivative Instruments and Hedging (Tables)
9 Months Ended
Sep. 30, 2020
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 Networks' derivative positions as of September 30, 2020 and December 31, 2019, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:
As of September 30, 2020Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)    
Not designated as hedging instruments    
Derivative assets$11 $$$
Derivative liabilities(7)(1)(26)(83)
(19)(82)
Designated as hedging instruments
Derivative assets— — — — 
Derivative liabilities— — (1)— 
— — (1)— 
Total derivatives before offset of cash collateral(20)(82)
Cash collateral receivable — — 
Total derivatives as presented in the balance sheet
$$$(14)$(79)
As of December 31, 2019Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)    
Not designated as hedging instruments    
Derivative assets$$$$
Derivative liabilities(1)(2)(39)(86)
— (38)(84)
Designated as hedging instruments
Derivative assets— — — — 
Derivative liabilities— — (1)(1)
— — (1)(1)
Total derivatives before offset of cash collateral— (39)(85)
Cash collateral receivable— — 27 
Total derivatives as presented in the balance sheet
$— $$(12)$(84)
The tables below present Renewables' derivative positions as of September 30, 2020 and December 31, 2019, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:
As of September 30, 2020Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets$49 $111 $$
Derivative liabilities(26)(13)(3)(2)
23 98 (2)— 
Designated as hedging instruments
Derivative assets20 
Derivative liabilities(7)(15)(5)(3)
(2)(3)(2)
Total derivatives before offset of cash collateral21 103 (5)(2)
Cash collateral payable(8)(20)— — 
Total derivatives as presented in the balance sheet $13 $83 $(5)$(2)
As of December 31, 2019Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets$23 $110 $42 $13 
Derivative liabilities(1)(7)(48)(18)
22 103 (6)(5)
Designated as hedging instruments
Derivative assets— 18 
Derivative liabilities— (9)(13)(6)
— (8)(2)
Total derivatives before offset of cash collateral22 112 (14)(7)
Cash collateral (payable) receivable(11)(30)
Total derivatives as presented in the balance sheet$11 $82 $(7)$(1)
Schedule of Notional Volumes of Outstanding Derivative Positions
The net notional volumes of the outstanding derivative instruments associated with Networks activities as of September 30, 2020 and December 31, 2019, respectively, consisted of:
 September 30,December 31,
As of20202019
(Millions)  
Wholesale electricity purchase contracts (MWh)5.1 5.1 
Natural gas purchase contracts (Dth)8.8 8.5 
Fleet fuel purchase contracts (Gallons)2.4 2.2 
The net notional volumes of outstanding derivative instruments associated with Renewables activities as of September 30, 2020 and December 31, 2019, respectively, consisted of:
September 30,December 31,
As of20202019
(MWh/Dth in millions)  
Wholesale electricity purchase contracts
Wholesale electricity sales contracts
Natural gas and other fuel purchase contracts29 29 
Financial power contracts12 10 
Basis swaps – purchases40 42 
Basis swaps – sales— 
Schedule 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 September 30, 2020 and December 31, 2019 and amounts reclassified from regulatory assets and liabilities into income for the three and nine months ended September 30, 2020 and 2019 are as follows:
(Millions)Loss or Gain Recognized in Regulatory Assets/LiabilitiesLocation of Loss Reclassified from Regulatory Assets/Liabilities into IncomeLoss Reclassified from Regulatory Assets/Liabilities into Income
As ofThree Months Ended September 30,Nine Months Ended September 30,
September 30, 2020ElectricityNatural Gas2020 ElectricityNatural GasElectricityNatural Gas
Regulatory assets$$— Purchased power, natural gas and fuel used$$— $41 $
Regulatory liabilities$— $(4)
December 31, 20192019 
Regulatory assets$24 $Purchased power, natural gas and fuel used$$— $16 $— 
The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three and nine months ended September 30, 2020 and 2019, respectively, were as follows:
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(Millions)    
Derivative assets$— $— $— $(3)
Derivative liabilities$$$$
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,(Loss) Recognized in OCI on Derivatives (a)Location of Loss (Gain) Reclassified from Accumulated OCI into IncomeLoss (Gain) Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Interest rate contracts$— Interest expense$$86 
Commodity contracts(1)Purchased power, natural gas and fuel used— 259 
Foreign currency exchange contracts
— — 
Total$(1)$1 
2019
Interest rate contracts$— Interest expense$$72 
Commodity contracts— Purchased power, natural gas and fuel used(1)279 
Foreign currency exchange contracts
(5)— 
Total$(5)$ 
Nine Months Ended September 30,(Loss) Gain Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss (Gain) Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Interest rate contracts$— Interest expense$$251 
Commodity contracts(2)Purchased power, natural gas and fuel used999 
Foreign currency exchange contracts
(2)— 
Total$(4)$4 
2019
Interest rate contracts$— Interest expense$$226 
Commodity contracts— Purchased power, natural gas and fuel used(1)1,101 
Foreign currency exchange contracts
(4)— 
Total$(4)$4 
(a) Changes in accumulated OCI are reported on a pre-tax basis.
The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,(Loss) Gain Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Commodity contracts$(17)Operating revenues$$1,470 
2019
Commodity contracts$13 Operating revenues$$1,487 
Nine Months Ended September 30,(Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Commodity contracts$(9)Operating revenues$$4,651 
2019
Commodity contracts$(2)Operating revenues$$4,729 
(a) Changes in OCI are reported on a pre-tax basis.
The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,Gain (Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Interest rate contracts$— Interest expense$$86 
2019
Interest rate contracts$— Interest expense$$72 
Nine Months Ended September 30,(Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2020
Interest rate contracts$(27)Interest expense$$251 
2019
Interest rate contracts$(24)Interest expense$$226 
(a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods.
Schedule of Fair Value, Net Derivative Contracts
The fair values of derivative contracts associated with Renewables activities as of September 30, 2020 and December 31, 2019, respectively, consisted of:
September 30,December 31,
As of20202019
(Millions)  
Wholesale electricity purchase contracts$$10 
Wholesale electricity sales contracts
Natural gas and other fuel purchase contracts(2)
Financial power contracts62 73 
Basis swaps – purchases12 — 
Total$89 $85 
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 nine months ended September 30, 2020, consisted of:
Three Months Ended Nine Months Ended
September 30, 2020September 30, 2020
TradingNon-tradingTotal amount per income statementTradingNon-tradingTotal amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts$$— $$— 
Wholesale electricity sales contracts(7)(11)(1)
Financial power contracts(12)
Financial and natural gas contracts— (8)— (13)
Total (loss) gain included in operating revenues
$— $(31)$1,470 $$(7)$4,651 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts$— $$— $(2)
Wholesale electricity sales contracts— — — 
Financial and natural gas contracts— 16 — 19 
Total gain included in purchased power, natural gas and fuel used$— $26 $259 $— $17 $999 
Total (Loss) Gain $— $(5)$$10 
The effects of trading and non-trading derivatives associated with Renewables activities for the three and nine months ended September 30, 2019, consisted of:
Three Months Ended Nine Months Ended
September 30, 2019September 30, 2019
TradingNon-tradingTotal amount per income statementTradingNon-tradingTotal amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts$(1)$— $(2)$— 
Wholesale electricity sales contracts— 42 37 
Financial power contracts— 13 — 22 
Financial and natural gas contracts— (1)
Total (loss) gain included in operating revenues$(1)$56 $1,487 $(1)$60 $4,729 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts$— $(19)$— $(2)
Financial power contracts— — — (2)
Financial and natural gas contracts— — 10 
Total (loss) gain included in purchased power, natural gas and fuel used
$— $(13)$279 $— $$1,101 
Total (Loss) Gain $(1)$43 $(1)$66 
v3.20.2
Post-retirement and Similar Obligations (Tables)
9 Months Ended
Sep. 30, 2020
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 nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(Millions)    
Service cost$12 $10 $35 $30 
Interest cost27 33 81 98 
Expected return on plan assets(50)(48)(150)(144)
Amortization of:
Prior service costs— — — (1)
Actuarial loss31 28 94 85 
Net Periodic Benefit Cost$20 $23 $60 $68 
The components of net periodic benefit cost for postretirement benefits for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of: 
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(Millions)    
Service cost$$$$
Interest cost10 12 
Expected return on plan assets(2)(1)(6)(5)
Amortization of:
Prior service costs(3)(3)(7)(7)
Actuarial loss— — (1)
Net Periodic Benefit Cost$ $1 $ $1 
v3.20.2
Equity (Tables)
9 Months Ended
Sep. 30, 2020
Equity [Abstract]  
Schedule of Accumulated Other Comprehensive Gain (Loss)
Accumulated Other Comprehensive Loss for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:
As of June 30,Three Months Ended September 30,As of September 30,As of June 30,Three Months Ended September 30,As of September 30,
202020202020201920192019
(Millions)      
Change in revaluation of defined benefit plans
$(12)$— $(12)$(13)$— $(13)
Loss on nonqualified pension plans(7)— (7)(7)— (7)
Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $(3) for 2020 and $2 for 2019
(29)(15)(44)(18)(13)
Reclassification to net income of losses on cash flow hedges, net of income tax expense of $0 for 2020 and $1 for 2019(a)
(60)(51)(71)(66)
(Loss) Gain on derivatives qualifying as cash flow hedges(89)(6)(95)(89)10 (79)
Accumulated Other Comprehensive (Loss) Income
$(108)$(6)$(114)$(109)$10 $(99)
As of December 31,Nine Months Ended September 30,As of September 30,As of December 31,Adoption of new accountingNine Months Ended September 30,As of September 30,
2019202020202018standard20192019
(Millions)      
Change in revaluation of defined benefit plans
$(12)$— $(12)$(11)$(2)$— $(13)
Loss on nonqualified pension plans(7)— (7)(6)— (1)(7)
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(8) for both 2020 and 2019
(13)(31)(44)— (22)(13)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense of $1 for 2020 and $2 for 2019(a)
(63)12 (51)(64)(10)(66)
Loss on derivatives qualifying as cash flow hedges
(76)(19)(95)(55)(10)(14)(79)
Accumulated Other Comprehensive Loss
$(95)$(19)$(114)$(72)$(12)$(15)$(99)
(a)Reclassification is reflected in the operating expenses line item in our condensed consolidated statements of income.
v3.20.2
Earnings Per Share (Tables)
9 Months Ended
Sep. 30, 2020
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 nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(Millions, except for number of shares and per share data)    
Numerator:    
Net income attributable to AVANGRID$87 $150 $415 $477 
Denominator:
Weighted average number of shares outstanding - basic309,491,082 309,491,082 309,496,234 309,491,082 
Weighted average number of shares outstanding - diluted309,550,126 309,517,778 309,554,838 309,512,301 
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic$0.28 $0.48 $1.34 $1.54 
Earnings Per Common Share, Diluted$0.28 $0.48 $1.34 $1.54 
v3.20.2
Segment Information (Tables)
9 Months Ended
Sep. 30, 2020
Segment Reporting [Abstract]  
Schedule of Segment Information
Segment information as of and for the three and nine months ended September 30, 2020, consisted of:
Three Months Ended September 30, 2020NetworksRenewablesOther (a)AVANGRID Consolidated
(Millions)    
Revenue - external$1,194 $275 $$1,470 
Revenue - intersegment(4)— 
Depreciation and amortization151 104 — 255 
Operating income (loss)160 (2)165 
Earnings (losses) from equity method investments(2)— 
Interest expense, net of capitalization63 (1)24 86 
Income tax expense (benefit)20 (7)15 
Adjusted net income$99 $32 $(31)$100 
Nine Months Ended September 30, 2020NetworksRenewablesOther (a)AVANGRID Consolidated
(Millions)    
Revenue - external$3,775 $875 $$4,651 
Revenue - intersegment(5)— 
Depreciation and amortization446 301 748 
Operating income617 24 647 
Earnings (losses) from equity method investments(11)— (3)
Interest expense, net of capitalization199 (1)53 251 
Income tax expense (benefit)75 (53)(1)21 
Adjusted net income379 108 (53)434 
Capital expenditures1,312 648 — 1,960 
As of September 30, 2020
Property, plant and equipment16,640 9,782 10 26,432 
Equity method investments138 530 — 668 
Total assets$24,178 $12,694 $(1,232)$35,640 
(a) Includes Corporate and intersegment eliminations.
Segment information for the three and nine months ended September 30, 2019 and as of December 31, 2019, consisted of:
Three Months Ended September 30, 2019NetworksRenewablesOther (a)AVANGRID Consolidated
(Millions)    
Revenue - external$1,139 $347 $$1,487 
Revenue - intersegment— (1)— 
Depreciation and amortization138 98 237 
Operating income182 53 239 
Earnings (losses) from equity method investments(4)— (1)
Interest expense, net of capitalization66 (1)72 
Income tax expense28 33 
Adjusted net income$89 $46 $(12)$123 
Nine Months Ended September 30, 2019NetworksRenewablesOther (a)AVANGRID
Consolidated
(Millions)    
Revenue - external$3,831 $896 $$4,729 
Revenue - intersegment— (6)— 
Depreciation and amortization407 273 681 
Operating income668 115 787 
Earnings (losses) from equity method investments(7)— 
Interest expense, net of capitalization201 19 226 
Income tax expense (benefit)117 (15)103 
Adjusted net income355 115 (28)442 
Capital expenditures1,086 959 — 2,045 
As of December 31, 2019    
Property, plant and equipment15,840 9,368 10 25,218 
Equity method investments139 506 — 645 
Total assets$23,250 $13,163 $(1,997)$34,416 
(a) Includes Corporate 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 nine months ended September 30, 2020 and 2019, respectively, is as follows:
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(Millions)    
Adjusted Net Income Attributable to Avangrid, Inc.$100 $123 $434 $442 
Adjustments:
Mark-to-market earnings - Renewables (1)(7)42 66 
Restructuring charges (2)(1)(2)(5)(4)
Accelerated depreciation from repowering (3)(3)(5)(9)(15)
Impact of COVID-19 (4)(8)— (21)— 
Income tax impact of adjustments(9)(12)
Net Income Attributable to Avangrid, Inc.$87 $150 $415 $477 
(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.
(2)Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth.
(3)Represents the amount of accelerated depreciation derived from repowering of wind farms in Renewables.
(4)Represents costs incurred in connection with the COVID-19 pandemic.
v3.20.2
Related Party Transactions (Tables)
9 Months Ended
Sep. 30, 2020
Related Party Transactions [Abstract]  
Schedule of Related Party Transactions
Related party transactions for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:
Three Months Ended September 30,20202019
(Millions)Sales ToPurchases FromSales ToPurchases From
Iberdrola Renovables Energía, S.L.$— $(2)$— $(1)
Iberdrola Financiación, S.A.$— $(3)$— $(1)
Iberdrola, S.A.$— $(10)$— $(8)
Vineyard Wind$$— $$— 
Iberdrola Solutions$$— $— $— 
Other$— $(1)$— $(1)
Nine Months Ended September 30,20202019
(Millions)Sales ToPurchases FromSales ToPurchases From
Iberdrola Renovables Energía, S.L.$— $(6)$— $(10)
Iberdrola Financiación, S.A.$— $(5)$— $(2)
Iberdrola, S.A.$— $(31)$— $(28)
Vineyard Wind$$— $11 $— 
Iberdrola Solutions$$— $— $— 
Other$— $(2)$$(2)
Schedule of Related Party Balances
Related party balances as of September 30, 2020 and December 31, 2019, respectively, consisted of:
As ofSeptember 30, 2020December 31, 2019
(Millions)Owed ByOwed ToOwed ByOwed To
Iberdrola, S.A.$$(32)$$(42)
Iberdrola Renovables Energía, S.L.$— $(6)$— $— 
Iberdrola Financiación, S.A.$— $(4)$— $— 
Vineyard Wind$$— $$— 
Iberdrola Solutions$$(4)$— $— 
Siemens-Gamesa (a)$— $— $— $(18)
Other$$(1)$$(4)
(a) After Iberdrola's sale of its interest of Siemens-Gamesa in February 2020, transactions with Siemens-Gamesa are no longer considered related party.
v3.20.2
Other Financial Statement Items (Tables)
9 Months Ended
Sep. 30, 2020
Balance Sheet Related Disclosures [Abstract]  
Schedule of Accounts, Notes, Loans and Financing Receivable
Accounts receivable and unbilled revenues, net as of September 30, 2020 and December 31, 2019 consisted of:
As of September 30, 2020December 31, 2019
(Millions)
Trade receivables and unbilled revenues$1,115 $1,151 
Allowance for credit losses(94)(69)
Accounts receivable and unbilled revenues, net$1,021 $1,082 
Schedule of Accounts Receivable, Allowance for Credit Loss
The change in the allowance for credit losses for the three and nine months ended September 30, 2020 and 2019 consisted of:
Three Months Ended September 30,Nine Months Ended September 30,
(Millions)2020201920202019
As of Beginning of Period,$85 $73 $69 $62 
Current period provision19 24 60 71 
Write-off as uncollectible(10)(24)(35)(60)
As of September 30,$94 $73 $94 $73 
Schedule of Accumulated Depreciation and Amortization
The accumulated depreciation and amortization as of September 30, 2020 and December 31, 2019, respectively, were as follows:
 September 30,December 31,
As of20202019
(Millions)  
Property, plant and equipment  
Accumulated depreciation$9,713 $9,059 
Intangible assets  
Accumulated amortization$315 $305 
v3.20.2
Restructuring and Severance Related Expenses (Tables)
9 Months Ended
Sep. 30, 2020
Restructuring and Related Activities [Abstract]  
Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities
As of September 30, 2020, 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:
 Nine Months Ended September 30, 2020
 (Millions)
Beginning Balance $
Restructuring and severance related expenses
Payments(3)
Ending Balance $
v3.20.2
Background and Nature Of Operations (Detail)
Sep. 30, 2020
Avangrid | Iberdrola S.A.  
Nature Of Business [Line Items]  
Percentage of equity owned by parent 81.50%
v3.20.2
Significant Accounting Policies and New Accounting Pronouncements - Narrative (Details) - USD ($)
$ in Millions
Sep. 30, 2020
Jun. 30, 2020
Jan. 01, 2020
Dec. 31, 2019
Sep. 30, 2019
Jun. 30, 2019
Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]              
Cumulative adjustment to retained earnings $ (15,854) $ (15,916)   $ (15,586) $ (15,518) $ (15,549) $ (15,403)
Retained Earnings              
New Accounting Pronouncements or Change in Accounting Principle [Line Items]              
Cumulative adjustment to retained earnings $ (1,684) $ (1,733)   (1,681) $ (1,599) $ (1,594) (1,528)
Cumulative Effect, Period of Adoption, Adjustment              
New Accounting Pronouncements or Change in Accounting Principle [Line Items]              
Cumulative adjustment to retained earnings       1     1
Cumulative Effect, Period of Adoption, Adjustment | Retained Earnings              
New Accounting Pronouncements or Change in Accounting Principle [Line Items]              
Cumulative adjustment to retained earnings     $ 1 $ 1     $ (11)
v3.20.2
Revenue - Narrative (Detail) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Dec. 31, 2019
Disaggregation of Revenue [Line Items]          
Contract assets $ 12   $ 12   $ 12
TCC contract liabilities 6   6   10
Revenue recognized 6 $ 7 16 $ 16  
Accounts receivable related to contracts with customers 988   988   1,050
Unbilled revenues 266   266   $ 345
Revenue, remaining performance obligation, amount 245   245    
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-10-01          
Disaggregation of Revenue [Line Items]          
Revenue, remaining performance obligation, amount 24   24    
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01          
Disaggregation of Revenue [Line Items]          
Revenue, remaining performance obligation, amount 67   67    
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01          
Disaggregation of Revenue [Line Items]          
Revenue, remaining performance obligation, amount 42   42    
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01          
Disaggregation of Revenue [Line Items]          
Revenue, remaining performance obligation, amount 25   25    
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01          
Disaggregation of Revenue [Line Items]          
Revenue, remaining performance obligation, amount 17   17    
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01          
Disaggregation of Revenue [Line Items]          
Revenue, remaining performance obligation, amount 14   14    
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01          
Disaggregation of Revenue [Line Items]          
Revenue, remaining performance obligation, amount $ 80   $ 80    
Renewables          
Disaggregation of Revenue [Line Items]          
Capitalized contract cost amortization term     15 years    
v3.20.2
Revenue - Narrative Revenue Term (Details) - Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-10-01
Sep. 30, 2020
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Auction period 3 months
Transmission congestion contracts | Min.  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Auction period 6 months
Transmission congestion contracts | Max.  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Auction period 2 years
v3.20.2
Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Detail) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Segment Reporting Information [Line Items]        
Operating revenues $ 1,405 $ 1,372 $ 4,402 $ 4,461
Leasing revenue 2 1 5 5
Derivative revenue 25 84 111 173
Alternative revenue programs 24 13 109 48
Other revenue 14 17 24 42
Total operating revenues 1,470 1,487 4,651 4,729
Electricity        
Segment Reporting Information [Line Items]        
Operating revenues 984 922 2,701 2,637
Natural Gas        
Segment Reporting Information [Line Items]        
Operating revenues 166 179 910 1,053
Wind Energy        
Segment Reporting Information [Line Items]        
Operating revenues 200 218 639 621
Solar Energy        
Segment Reporting Information [Line Items]        
Operating revenues 6 9 16 22
Thermal Energy        
Segment Reporting Information [Line Items]        
Operating revenues 13 5 27 21
Other        
Segment Reporting Information [Line Items]        
Operating revenues 36 39 109 107
Other        
Segment Reporting Information [Line Items]        
Operating revenues (4) 0 (4) (4)
Leasing revenue 0 0 0 0
Derivative revenue 0 0 0 0
Alternative revenue programs 0 0 0 0
Other revenue 1 0 0 0
Total operating revenues (3) 0 (4) (4)
Other | Electricity        
Segment Reporting Information [Line Items]        
Operating revenues 0 0 0 0
Other | Natural Gas        
Segment Reporting Information [Line Items]        
Operating revenues 0 0 0 0
Other | Wind Energy        
Segment Reporting Information [Line Items]        
Operating revenues 0 0 0 0
Other | Solar Energy        
Segment Reporting Information [Line Items]        
Operating revenues 0 0 0 0
Other | Thermal Energy        
Segment Reporting Information [Line Items]        
Operating revenues 0 0 0 0
Other | Other        
Segment Reporting Information [Line Items]        
Operating revenues (4) 0 (4) (4)
Networks        
Segment Reporting Information [Line Items]        
Operating revenues 1,162 1,117 3,649 3,761
Leasing revenue 2 1 5 5
Derivative revenue 0 0 0 0
Alternative revenue programs 24 13 109 48
Other revenue 9 9 16 23
Total operating revenues 1,197 1,140 3,779 3,837
Networks | Electricity        
Segment Reporting Information [Line Items]        
Operating revenues 984 922 2,701 2,637
Networks | Natural Gas        
Segment Reporting Information [Line Items]        
Operating revenues 166 179 910 1,053
Networks | Wind Energy        
Segment Reporting Information [Line Items]        
Operating revenues 0 0 0 0
Networks | Solar Energy        
Segment Reporting Information [Line Items]        
Operating revenues 0 0 0 0
Networks | Thermal Energy        
Segment Reporting Information [Line Items]        
Operating revenues 0 0 0 0
Networks | Other        
Segment Reporting Information [Line Items]        
Operating revenues 12 16 38 71
Renewables        
Segment Reporting Information [Line Items]        
Operating revenues 247 255 757 704
Leasing revenue 0 0 0 0
Derivative revenue 25 84 111 173
Alternative revenue programs 0 0 0 0
Other revenue 4 8 8 19
Total operating revenues 276 347 876 896
Renewables | Electricity        
Segment Reporting Information [Line Items]        
Operating revenues 0 0 0 0
Renewables | Natural Gas        
Segment Reporting Information [Line Items]        
Operating revenues 0 0 0 0
Renewables | Wind Energy        
Segment Reporting Information [Line Items]        
Operating revenues 200 218 639 621
Renewables | Solar Energy        
Segment Reporting Information [Line Items]        
Operating revenues 6 9 16 22
Renewables | Thermal Energy        
Segment Reporting Information [Line Items]        
Operating revenues 13 5 27 21
Renewables | Other        
Segment Reporting Information [Line Items]        
Operating revenues $ 28 $ 23 $ 75 $ 40
v3.20.2
Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Detail)
$ in Millions
Sep. 30, 2020
USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 245
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-10-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 24
Remaining performance obligation, period 3 months
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 $ 67
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 42
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 25
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 17
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 14
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues 80
Retail Energy Sales Contracts In Place  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues 4
Retail Energy Sales Contracts In Place | 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 $ 1
Remaining performance obligation, period 1 year
Retail Energy Sales Contracts In Place | 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 $ 1
Remaining performance obligation, period 1 year
Retail Energy Sales Contracts In Place | 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 $ 1
Remaining performance obligation, period 1 year
Retail Energy Sales Contracts In Place | 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 $ 1
Remaining performance obligation, period 1 year
Retail Energy Sales Contracts In Place | 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 $ 0
Remaining performance obligation, period 1 year
Retail Energy Sales Contracts In Place | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 0
Remaining performance obligation, period
Capacity And Carbon Free Energy Sale Contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 175
Capacity And Carbon Free Energy Sale Contracts | 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 $ 39
Remaining performance obligation, period 1 year
Capacity And Carbon Free Energy Sale Contracts | 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 $ 23
Remaining performance obligation, period 1 year
Capacity And Carbon Free Energy Sale Contracts | 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 $ 15
Remaining performance obligation, period 1 year
Capacity And Carbon Free Energy Sale Contracts | 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 $ 12
Remaining performance obligation, period 1 year
Capacity And Carbon Free Energy Sale Contracts | 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 $ 11
Remaining performance obligation, period 1 year
Capacity And Carbon Free Energy Sale Contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 75
Remaining performance obligation, period
Renewable Energy Credit Sale Contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 66
Renewable Energy Credit Sale Contracts | 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
Remaining performance obligation, period 1 year
Renewable Energy Credit Sale Contracts | 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
Remaining performance obligation, period 1 year
Renewable Energy Credit Sale Contracts | 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
Remaining performance obligation, period 1 year
Renewable Energy Credit Sale Contracts | 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 $ 4
Remaining performance obligation, period 1 year
Renewable Energy Credit Sale Contracts | 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 $ 3
Remaining performance obligation, period 1 year
Renewable Energy Credit Sale Contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 5
Remaining performance obligation, period
v3.20.2
Regulatory Assets and Liabilities - Additional Information (Detail) - USD ($)
$ in Millions
1 Months Ended 3 Months Ended 9 Months Ended 12 Months Ended
Jun. 22, 2020
Feb. 19, 2020
May 20, 2019
Jan. 18, 2019
Dec. 19, 2018
Dec. 31, 2017
Dec. 31, 2016
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Apr. 30, 2019
Apr. 30, 2018
Apr. 30, 2017
Dec. 31, 2018
Regulatory Assets And Liabilities [Line Items]                              
Unrecorded regulatory assets               $ 1,616.0   $ 1,616.0          
Equity ratio           50.00%                  
Rate case filing, extension period 1 month                            
Public utilities regulatory authority distribution rate             9.10%                
Equity ratio, year three               55.00%   55.00%          
UIL Holdings                              
Regulatory Assets And Liabilities [Line Items]                              
Business combination merger related rate credits               $ 1.0 $ 1.0 $ 2.0 $ 2.0        
Max. | New York                              
Regulatory Assets And Liabilities [Line Items]                              
Deferred income tax recovery period                   39 years          
Min. | 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%  
NYSEG                              
Regulatory Assets And Liabilities [Line Items]                              
Regulatory items amortization period                   3 years          
Annual amortization of regulatory items                   $ 16.5          
Recovery of deferred storm costs over ten-year               69.0   69.0          
Recovery of deferred storm costs over five-year               $ 16.0   16.0          
Storm costs not included in joint proposal                   $ 196.0          
NYSEG | Regulatory Items Other Than Storm Costs                              
Regulatory Assets And Liabilities [Line Items]                              
Regulatory items amortization period                   5 years          
NYSEG | Storm costs                              
Regulatory Assets And Liabilities [Line Items]                              
Regulatory items amortization period                   10 years          
NYSEG Electric | Deferred Income Tax Charge                              
Regulatory Assets And Liabilities [Line Items]                              
Regulatory items amortization period                   50 years          
RG&E                              
Regulatory Assets And Liabilities [Line Items]                              
Approved return on equity                   9.00%          
Equity ratio               48.00%   48.00%          
Storm costs not included in joint proposal                   $ 61.0          
RG&E | Max.                              
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          
NYDPS                              
Regulatory Assets And Liabilities [Line Items]                              
Equity ratio for earnings sharing     48.00%                        
Return on equity     8.80%                        
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                   $ 2.0          
Amount of approved ROE for the year 2019                   5.0          
Amount of approved ROE for the year 2020                   $ 5.0          
Connecticut Natural Gas Corporation                              
Regulatory Assets And Liabilities [Line Items]                              
Amount of proposed ROE for the year 2019         $ 10.0                    
Amount of proposed ROE for the year 2020         5.0                    
Amount of proposed ROE for the year 2021         $ 5.0                    
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       $ 2.0                      
Amount of approved ROE for the year 2019       $ 1.0                      
Central Maine Power                              
Regulatory Assets And Liabilities [Line Items]                              
Distribution revenue requirement   $ 17.0                          
Annual distribution tariff increase percentage   7.00%                          
Distribution tariff rate increased based on ROE   9.25%                          
Distribution tariff rate increased based on equity capital   50.00%                          
ROE reduction   1.00%                          
Proposed distribution tariff rate decrease based on return on equity   8.25%                          
Service quality measures for a period   18 months                          
Deferred income tax recovery period                   32 years 6 months          
v3.20.2
Regulatory Assets and Liabilities - Rate Increases and Delivery Rate Percentages (Details)
$ in Thousands
Jun. 22, 2020
USD ($)
NYSEG Electric | Electric and Gas Service Rate Plan Year One  
Regulatory Liabilities [Line Items]  
Rate Increase $ 34,700
Delivery Rate Increase 4.60%
NYSEG Electric | Electric and Gas Service Rate Plan Year Two  
Regulatory Liabilities [Line Items]  
Rate Increase $ 71,510
Delivery Rate Increase 9.10%
NYSEG Electric | Electric and Gas Service Rate Plan Year Three  
Regulatory Liabilities [Line Items]  
Rate Increase $ 79,400
Delivery Rate Increase 9.10%
NYSEG Gas | Electric and Gas Service Rate Plan Year One  
Regulatory Liabilities [Line Items]  
Rate Increase $ 0
Delivery Rate Increase 0.00%
NYSEG Gas | Electric and Gas Service Rate Plan Year Two  
Regulatory Liabilities [Line Items]  
Rate Increase $ 1,580
Delivery Rate Increase 0.80%
NYSEG Gas | Electric and Gas Service Rate Plan Year Three  
Regulatory Liabilities [Line Items]  
Rate Increase $ 3,300
Delivery Rate Increase 1.60%
RG&E Electric | Electric and Gas Service Rate Plan Year One  
Regulatory Liabilities [Line Items]  
Rate Increase $ 10,700
Delivery Rate Increase 2.40%
RG&E Electric | Electric and Gas Service Rate Plan Year Two  
Regulatory Liabilities [Line Items]  
Rate Increase $ 22,920
Delivery Rate Increase 5.20%
RG&E Electric | Electric and Gas Service Rate Plan Year Three  
Regulatory Liabilities [Line Items]  
Rate Increase $ 25,400
Delivery Rate Increase 5.20%
RG&E Gas | Electric and Gas Service Rate Plan Year One  
Regulatory Liabilities [Line Items]  
Rate Increase $ 0
Delivery Rate Increase 0.00%
RG&E Gas | Electric and Gas Service Rate Plan Year Two  
Regulatory Liabilities [Line Items]  
Rate Increase $ 0
Delivery Rate Increase 0.00%
RG&E Gas | Electric and Gas Service Rate Plan Year Three  
Regulatory Liabilities [Line Items]  
Rate Increase $ 2,400
Delivery Rate Increase 1.30%
v3.20.2
Regulatory Assets and Liabilities - Current and Non-Current Assets (Detail) - USD ($)
$ in Millions
Sep. 30, 2020
Dec. 31, 2019
Regulatory Assets [Line Items]    
Total regulatory assets $ 2,843 $ 2,861
Less: current portion 252 294
Total non-current regulatory assets 2,591 2,567
Pension and other post-retirement benefits cost deferrals    
Regulatory Assets [Line Items]    
Total regulatory assets 101 125
Pension and other post-retirement benefits    
Regulatory Assets [Line Items]    
Total regulatory assets 963 1,061
Storm costs    
Regulatory Assets [Line Items]    
Total regulatory assets 418 272
Rate adjustment mechanism    
Regulatory Assets [Line Items]    
Total regulatory assets 16 79
Revenue decoupling mechanism    
Regulatory Assets [Line Items]    
Total regulatory assets 56 19
Transmission revenue reconciliation mechanism    
Regulatory Assets [Line Items]    
Total regulatory assets 9 5
Contracts for differences    
Regulatory Assets [Line Items]    
Total regulatory assets 90 92
Hardship programs    
Regulatory Assets [Line Items]    
Total regulatory assets 26 29
Plant decommissioning    
Regulatory Assets [Line Items]    
Total regulatory assets 0 5
Deferred purchased gas    
Regulatory Assets [Line Items]    
Total regulatory assets 14 25
Deferred transmission expense    
Regulatory Assets [Line Items]    
Total regulatory assets 14 11
Environmental remediation costs    
Regulatory Assets [Line Items]    
Total regulatory assets 278 277
Debt premium    
Regulatory Assets [Line Items]    
Total regulatory assets 88 97
Unamortized losses on reacquired debt    
Regulatory Assets [Line Items]    
Total regulatory assets 27 29
Unfunded future income taxes    
Regulatory Assets [Line Items]    
Total regulatory assets 408 399
Federal tax depreciation normalization adjustment    
Regulatory Assets [Line Items]    
Total regulatory assets 149 153
Asset retirement obligation    
Regulatory Assets [Line Items]    
Total regulatory assets 21 17
Deferred meter replacement costs    
Regulatory Assets [Line Items]    
Total regulatory assets 25 27
COVID-19 cost recovery    
Regulatory Assets [Line Items]    
Total regulatory assets 2 0
Other    
Regulatory Assets [Line Items]    
Total regulatory assets $ 138 $ 139
v3.20.2
Regulatory Assets and Liabilities - Current and Non-Current Liabilities (Detail) - USD ($)
$ in Millions
Sep. 30, 2020
Dec. 31, 2019
Regulatory Liabilities [Line Items]    
Total regulatory liabilities $ 3,556 $ 3,523
Less: current portion 214 242
Total non-current regulatory liabilities 3,342 3,281
Energy efficiency portfolio standard    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 72 72
Gas supply charge and deferred natural gas cost    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 4 11
Pension and other post-retirement benefits cost deferrals    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 69 80
Carrying costs on deferred income tax bonus depreciation    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 32 49
Carrying costs on deferred income tax - Mixed Services 263(a)    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 11 15
2017 Tax Act    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 1,550 1,548
Revenue decoupling mechanism    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 10 17
Accrued removal obligations    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 1,181 1,173
Asset sale gain account    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 10 10
Economic development    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 27 27
Positive benefit adjustment    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 35 37
Theoretical reserve flow thru impact    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 10 14
Deferred property tax    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 52 17
Net plant reconciliation    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 23 23
Debt rate reconciliation    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 83 67
Rate refund – FERC ROE proceeding    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 33 32
Transmission congestion contracts    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 24 23
Merger-related rate credits    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 14 16
Accumulated deferred investment tax credits    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 26 13
Asset retirement obligation    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 16 14
Earning sharing provisions    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 26 28
Middletown/Norwalk local transmission network service collections    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 18 18
Low income programs    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 29 33
Non-firm margin sharing credits    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 15 16
New York 2018 winter storm settlement    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 11 11
Other    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities $ 175 $ 159
v3.20.2
Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($)
$ in Millions
9 Months Ended
Sep. 30, 2020
Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Restricted cash $ 386 $ 311
Fair value of debt $ 9,216 8,168
Min.    
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 $ 5 $ 6
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%  
v3.20.2
Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Detail) - USD ($)
$ in Millions
Sep. 30, 2020
Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets $ 104 $ 95
Derivative liabilities (100) (105)
Equity investments with readily determinable fair values    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Financial instruments, assets 53 51
Derivative financial instruments - power    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 78 93
Derivative liabilities (5) (8)
Derivative financial instruments - gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 22 0
Derivative liabilities (1) (2)
Contracts for differences    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 2 2
Derivative liabilities (92) (94)
Derivative financial instruments – other    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 2  
Derivative liabilities (2) (1)
Netting    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets (104) (125)
Derivative liabilities 85 125
Netting | 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
Netting | Derivative financial instruments - power    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets (67) (54)
Derivative liabilities 77 92
Netting | Derivative financial instruments - gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets (37) (71)
Derivative liabilities 8 33
Netting | Contracts for differences    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 0 0
Derivative liabilities 0 0
Netting | 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 1    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 12 4
Derivative liabilities (17) (32)
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 41 38
Level 1 | Derivative financial instruments - power    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 8 4
Derivative liabilities (17) (28)
Level 1 | Derivative financial instruments - gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 4 0
Derivative liabilities 0 (4)
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 47 63
Derivative liabilities (36) (70)
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 12 13
Level 2 | Derivative financial instruments - power    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 19 23
Derivative liabilities (31) (43)
Level 2 | Derivative financial instruments - gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 26 40
Derivative liabilities (5) (26)
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 2  
Derivative liabilities 0 (1)
Level 3    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 149 153
Derivative liabilities (132) (128)
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 118 120
Derivative liabilities (34) (29)
Level 3 | Derivative financial instruments - gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 29 31
Derivative liabilities (4) (5)
Level 3 | Contracts for differences    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 2 2
Derivative liabilities (92) (94)
Level 3 | Derivative financial instruments – other    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 0  
Derivative liabilities $ (2) $ 0
v3.20.2
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 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
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, $ 16 $ (32) $ 25 $ (15)
Gains recognized in operating revenues 2 38 10 42
(Losses) recognized in operating revenues 0 (22) (4) (5)
Total gains recognized in operating revenues 2 16 6 37
Gains recognized in OCI 0 12 2 0
(Losses) recognized in OCI (1) 0 (7) (2)
Total gains (losses) recognized in OCI (1) 12 (5) (2)
Net change recognized in regulatory assets and liabilities 3 1 2 2
Purchases (1) 0 0 (23)
Settlements (1) 10 (9) 8
Transfers out of Level 3 (a) (1) 0 (2) 0
Fair Value Ending of Period, 17 7 17 7
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 $ 2 $ 16 $ 6 $ 37
v3.20.2
Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Detail)
9 Months Ended
Sep. 30, 2020
$ / MWh
$ / MMBTU
CME SWAPS MARKETS (NYMEX) | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability | $ / MMBTU 2.51
CME SWAPS MARKETS (NYMEX) | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability | $ / MMBTU 3.45
CME SWAPS MARKETS (NYMEX) | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability | $ / MMBTU 1.48
AECO | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability | $ / MMBTU 1.43
AECO | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability | $ / MMBTU 3.23
AECO | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability | $ / MMBTU (0.17)
Ameren | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 26.03
Ameren | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 40.53
Ameren | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 14.73
COB | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 33.12
COB | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 95.00
COB | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 8.20
ComEd | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 24.01
ComEd | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 39.26
ComEd | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 12.65
ERCOT N hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 32.30
ERCOT N hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 196.95
ERCOT N hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 11.25
Ercot S hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 32.66
Ercot S hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 203.37
Ercot S hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 11.41
Indiana Hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 28.16
Indiana Hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 43.58
Indiana Hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability, liability 16.36
Mid C | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 29.58
Mid C | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 95.00
Mid C | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 4.00
Minn Hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 22.75
Minn Hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 37.78
Minn Hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 11.52
Noil Hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 23.92
Noil Hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 39.01
Noil Hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 12.70
PJM W hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 28.41
PJM W hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 59.53
PJM W hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Variability 14.28
v3.20.2
Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Detail) - Contracts for differences - Level 3
Sep. 30, 2020
$ / kilowatt-MonthOfEnergy
Min. | Risk of non-performance  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 0.0059
Min. | Discount rate  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 0.0029
Min. | Forward pricing ($ per KW-month)  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 2.00
Max. | Risk of non-performance  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 0.0064
Max. | Discount rate  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 0.0049
Max. | Forward pricing ($ per KW-month)  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 5.30
v3.20.2
Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Detail) - USD ($)
$ in Millions
Sep. 30, 2020
Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative liabilities $ (9)  
Derivative Asset 104 $ 95
Derivative liabilities (100) (105)
Cash collateral (payable) receivable, Asset (23) (21)
Networks | Current Assets    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Asset 4 0
Cash collateral (payable) receivable, Asset 0 0
Total derivatives as presented in the balance sheet, Asset 4 0
Networks | Current Assets | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 11 1
Derivative liabilities (7) (1)
Derivative Asset 4 0
Networks | Current 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 | Noncurrent Assets    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Asset 2 2
Cash collateral (payable) receivable, Asset 0 0
Total derivatives as presented in the balance sheet, Asset 2 2
Networks | Noncurrent Assets | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 3 4
Derivative liabilities (1) (2)
Derivative Asset 2 2
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 (20) (39)
Cash collateral (payable) receivable, Liability 6 27
Total derivatives as presented in the balance sheet, Liability (14) (12)
Networks | Current Liabilities | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 7 1
Derivative liabilities (26) (39)
Derivative liabilities (19) (38)
Networks | Current Liabilities | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 0 0
Derivative liabilities (1) (1)
Derivative liabilities (1) (1)
Networks | Noncurrent Liabilities    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Liability (82) (85)
Cash collateral (payable) receivable, Liability 3 1
Total derivatives as presented in the balance sheet, Liability (79) (84)
Networks | Noncurrent Liabilities | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 1 2
Derivative liabilities (83) (86)
Derivative liabilities (82) (84)
Networks | Noncurrent Liabilities | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 0 0
Derivative liabilities 0 (1)
Derivative liabilities 0 (1)
Renewables | Current Assets    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Asset 21 22
Cash collateral (payable) receivable, Asset (8) (11)
Total derivatives as presented in the balance sheet, Asset 13 11
Renewables | Current Assets | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 49 23
Derivative liabilities (26) (1)
Derivative Asset 23 22
Renewables | Current Assets | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 5 0
Derivative liabilities (7) 0
Derivative Asset (2) 0
Renewables | Noncurrent Assets    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Asset 103 112
Cash collateral (payable) receivable, Asset (20) (30)
Total derivatives as presented in the balance sheet, Asset 83 82
Renewables | Noncurrent Assets | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 111 110
Derivative liabilities (13) (7)
Derivative Asset 98 103
Renewables | Noncurrent Assets | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 20 18
Derivative liabilities (15) (9)
Derivative Asset 5 9
Renewables | Current Liabilities    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Liability (5) (14)
Cash collateral (payable) receivable, Liability 0 7
Total derivatives as presented in the balance sheet, Liability (5) (7)
Renewables | Current Liabilities | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 1 42
Derivative liabilities (3) (48)
Derivative liabilities (2) (6)
Renewables | Current Liabilities | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 2 5
Derivative liabilities (5) (13)
Derivative liabilities (3) (8)
Renewables | Noncurrent Liabilities    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Liability (2) (7)
Cash collateral (payable) receivable, Liability 0 6
Total derivatives as presented in the balance sheet, Liability (2) (1)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 2 13
Derivative liabilities (2) (18)
Derivative liabilities 0 (5)
Renewables | Noncurrent Liabilities | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 1 4
Derivative liabilities (3) (6)
Derivative liabilities $ (2) $ (2)
v3.20.2
Derivative Instruments and Hedging - Net Notional Volume (Detail)
gal in Millions, dth in Millions, MWh in Millions
9 Months Ended 12 Months Ended
Sep. 30, 2020
gal
dth
MWh
Dec. 31, 2019
dth
MWh
gal
Networks | Wholesale Electricity Contract | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount | MWh 5.1 5.1
Networks | Natural Gas Contracts | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount 8.8 8.5
Networks | Fleet Fuel Contracts | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount | gal 2.4 2.2
Renewables | Wholesale Electricity Contract | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount (energy measure) | MWh 3.0 4.0
Renewables | Wholesale Electricity Contract | Short    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount (energy measure) | MWh 8.0 9.0
Renewables | Natural Gas and Other fuel Contracts | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount 29.0 29.0
Renewables | Financial Power Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount 12.0 10.0
Renewables | Basis swaps | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount 40.0 42.0
Renewables | Basis swaps | Short    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount 0.0 1.0
v3.20.2
Derivative Instruments and Hedging - Summary of Hedge Contracts Recognized in Regulatory Assets and Liabilities (Detail) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Dec. 31, 2019
Derivative Assets          
Derivative Instruments and Hedging Activities Disclosures [Line Items]          
Loss Reclassified from Regulatory Assets/Liabilities into Income $ 0 $ 0 $ 0 $ (3)  
Derivative Liabilities          
Derivative Instruments and Hedging Activities Disclosures [Line Items]          
Loss Reclassified from Regulatory Assets/Liabilities into Income 3 2 2 5  
Electricity | Regulatory Assets          
Derivative Instruments and Hedging Activities Disclosures [Line Items]          
Loss or Gain Recognized in Regulatory Assets/Liabilities 9   9   $ 24
Loss Reclassified from Regulatory Assets/Liabilities into Income 8 6 41 16  
Electricity | Derivative Liabilities          
Derivative Instruments and Hedging Activities Disclosures [Line Items]          
Loss or Gain Recognized in Regulatory Assets/Liabilities 0   0    
Natural Gas | Regulatory Assets          
Derivative Instruments and Hedging Activities Disclosures [Line Items]          
Loss or Gain Recognized in Regulatory Assets/Liabilities 0   0   $ 4
Loss Reclassified from Regulatory Assets/Liabilities into Income 0 $ 0 5 $ 0  
Natural Gas | Derivative Liabilities          
Derivative Instruments and Hedging Activities Disclosures [Line Items]          
Loss or Gain Recognized in Regulatory Assets/Liabilities $ (4)   $ (4)    
v3.20.2
Derivative Instruments and Hedging - Additional Information (Detail)
3 Months Ended 9 Months Ended
Dec. 31, 2020
USD ($)
Sep. 30, 2020
USD ($)
instrument
Sep. 30, 2019
USD ($)
Sep. 30, 2020
USD ($)
instrument
Sep. 30, 2019
USD ($)
Jan. 31, 2020
USD ($)
instrument
Dec. 31, 2019
USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Regulatory assets   $ 2,843,000,000   $ 2,843,000,000     $ 2,861,000,000
Gross amounts of recognized liabilities   9,000,000   9,000,000      
Regulatory liabilities   3,556,000,000   3,556,000,000     3,523,000,000
Cash collateral pledged   23,000,000   23,000,000     21,000,000
Not designated as hedging instruments              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Gain on foreign currency contracts not designated as hedging instruments   3,000,000 $ 0 3,000,000 $ 0    
UI              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Derivative collateral obligation to be paid in decrease in credit rating below investment grade   $ 13,000,000   $ 13,000,000      
Contracts for differences              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Number of derivative instruments | instrument   2   2      
Contracts for differences | UI              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Percentage of cost or benefit on contract allocated to customers       20.00%      
Gross derivative asset   $ 2,000,000   $ 2,000,000     2,000,000
Regulatory assets   90,000,000   90,000,000     92,000,000
Gross amounts of recognized liabilities   92,000,000   92,000,000     94,000,000
Regulatory liabilities   0   $ 0     0
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   89,000,000   89,000,000     92,000,000
Interest Rate Contract              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Gain (loss) recognized in OCI on derivatives   0 0 (27,000,000) (24,000,000)    
Interest Rate Contract | Cash Flow Hedging | Forecast              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Net loss in accumulated OCI related to discontinued cash flow hedge $ 2,000,000            
Previously Settled Interest Rate Contracts              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Gain (loss) recognized in OCI on derivatives   (2,000,000) (1,000,000) (5,000,000) (1,000,000)    
Previously Settled Interest Rate Contracts | Cash Flow Hedging              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Net loss related to previously settled forward starting swaps   59,000,000   59,000,000     38,000,000
Treasury lock              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Number of derivative instruments | instrument           2  
Derivative notional amount           $ 600,000,000  
Loss (Gain) Reclassified from Accumulated OCI into Income       27,000,000      
Networks              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Gain (loss) recognized in OCI on derivatives   (1,000,000) (5,000,000) (4,000,000) (4,000,000)    
Loss (Gain) Reclassified from Accumulated OCI into Income   1,000,000 0 4,000,000 4,000,000    
Networks | Cash Flow Hedging              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Gain (loss) recognized in OCI on derivatives   (1,000,000) (1,000,000) (3,000,000) $ (5,000,000)    
Unrealized losses on hedge derivatives reported in OCI       1,000,000      
Unrealized gains (losses) on hedge derivatives to be reclassified within next 12 months       (1,000,000)      
Networks | Cash Flow Hedging | Forecast              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Net loss in accumulated OCI related to discontinued cash flow hedge $ 1,000,000            
Networks | Swaps | Cash Flow Hedging              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Net loss related to previously settled forward starting swaps   $ 52,000,000   $ 52,000,000     $ 55,000,000
Networks | Fuel Derivatives | Cash Flow Hedging              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Maximum period of time of cash flow hedges       12 months      
Renewables              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Gain on sale of derivatives     $ 43,000,000        
Renewables | Cash Flow Hedging              
Derivative Instruments and Hedging Activities Disclosures [Line Items]              
Unrealized gains (losses) on hedge derivatives to be reclassified within next 12 months       $ (4,000,000)      
v3.20.2
Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Detail) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Interest expense $ 86 $ 72 $ 251 $ 226
Purchased power, natural gas and fuel used 259 279 999 1,101
Networks        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
(Loss) Gain Recognized in OCI on Derivatives (1) (5) (4) (4)
Loss (Gain) Reclassified from Accumulated OCI into Income 1 0 4 4
Interest Rate Contract        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
(Loss) Gain Recognized in OCI on Derivatives 0 0 (27) (24)
Interest Rate Contract | Interest Expense        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Loss (Gain) Reclassified from Accumulated OCI into Income 2 1 5 1
Interest Rate Contract | Networks | Interest Expense        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
(Loss) Gain Recognized in OCI on Derivatives 0 0 0 0
Loss (Gain) Reclassified from Accumulated OCI into Income 1 1 3 5
Commodity Contract | Networks | Operating Expense        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
(Loss) Gain Recognized in OCI on Derivatives (1) 0 (2) 0
Loss (Gain) Reclassified from Accumulated OCI into Income 0 (1) 1 (1)
Commodity Contract | Renewables        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
(Loss) Gain Recognized in OCI on Derivatives (17) 13 (9) (2)
Commodity Contract | Renewables | Operating revenues        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Loss (Gain) Reclassified from Accumulated OCI into Income 5 3 4 3
Foreign Exchange Contract | Networks | Operating Expense        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
(Loss) Gain Recognized in OCI on Derivatives 0 (5) (2) (4)
Loss (Gain) Reclassified from Accumulated OCI into Income $ 0 $ 0 $ 0 $ 0
v3.20.2
Derivative Instruments and Hedging - Fair Value of Derivative Contract (Detail) - Renewables - USD ($)
$ in Millions
Sep. 30, 2020
Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative fair value $ 89 $ 85
Financial Power Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative fair value 62 73
Long | Wholesale Electricity Contract    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative fair value 8 10
Long | Natural Gas and Other fuel Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative fair value 6 (2)
Short | Wholesale Electricity Contract    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative fair value $ 1 $ 4
v3.20.2
Derivative Instruments and Hedging - Effect of Trading and Non-trading Derivatives (Detail) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Revenues $ 1,470 $ 1,487 $ 4,651 $ 4,729
Utilities operating expense, purchased power 259 279 999 1,101
Renewables        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net       43
Revenues 276 347 876 896
Renewables | Trading        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net 0 (1) 1 (1)
Renewables | Non-trading        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net (5) 43 10 66
Operating revenues | Renewables | Trading        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net 0 (1) 1 (1)
Operating revenues | Renewables | Trading | Wholesale Electricity Contract | Long        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net 3 (1) 1 (2)
Operating revenues | Renewables | Trading | Wholesale Electricity Contract | Short        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net (7) 0 (1) 2
Operating revenues | Renewables | Trading | Financial Power Contracts        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net 4 0 1 0
Operating revenues | Renewables | Trading | Financial and Natural Gas Contracts        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net 0 0 0 (1)
Operating revenues | Renewables | Non-trading        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net (31) 56 (7) 60
Operating revenues | Renewables | Non-trading | Wholesale Electricity Contract | Long        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net 0 0 0 0
Operating revenues | Renewables | Non-trading | Wholesale Electricity Contract | Short        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net (11) 42 4 37
Operating revenues | Renewables | Non-trading | Financial Power Contracts        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net (12) 13 2 22
Operating revenues | Renewables | Non-trading | Financial and Natural Gas Contracts        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net (8) 1 (13) 1
Operating Expense | Renewables | Trading        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net 0 0 0 0
Operating Expense | Renewables | Trading | Wholesale Electricity Contract | Long        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net 0 0 0 0
Operating Expense | Renewables | Trading | Financial Power Contracts        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net   0   0
Operating Expense | Renewables | Trading | Financial and Natural Gas Contracts        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net 0 0 0 0
Operating Expense | Renewables | Non-trading        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net 26 (13) 17 6
Operating Expense | Renewables | Non-trading | Wholesale Electricity Contract | Long        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net 9 (19) (2) (2)
Operating Expense | Renewables | Non-trading | Financial Power Contracts        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net   0   (2)
Operating Expense | Renewables | Non-trading | Financial and Natural Gas Contracts        
Derivative Instruments and Hedging Activities Disclosures [Line Items]        
Derivative, gain (loss) on derivative, net $ 16 $ 6 $ 19 $ 10
v3.20.2
Contingencies (Detail)
$ in Millions
1 Months Ended 9 Months Ended
May 21, 2020
May 20, 2020
Mar. 22, 2016
Mar. 03, 2015
Oct. 16, 2014
Oct. 31, 2018
complaint
Apr. 30, 2018
Sep. 30, 2020
USD ($)
Dec. 31, 2019
USD ($)
May 01, 2018
USD ($)
Loss Contingencies [Line Items]                    
Regulatory liabilities               $ 3,342 $ 3,281  
Requested existing base return on equity base percentage 10.02% 9.88%                
Price of the power purchase agreements               259    
Requested renewables delay from preliminary proposed ruling period             2 years      
Standby letters of credit               449    
Amphora Gas Storage USA, LLC                    
Loss Contingencies [Line Items]                    
Claim for indemnification                   $ 20
Indemnification liability, percentage of purchase price                   15.00%
Indemnification liability, maximum amount                   $ 10
Complaint III                    
Loss Contingencies [Line Items]                    
Regulatory liabilities               7    
Complaint II                    
Loss Contingencies [Line Items]                    
Regulatory liabilities               26    
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% 9.88%        
Refund period term               15 months    
Number of claims | complaint           4        
Unfavorable Regulatory Action | Complaint I | Max.                    
Loss Contingencies [Line Items]                    
Approved return on equity     10.42% 11.74% 11.74%          
Unfavorable Regulatory Action | Complaint III                    
Loss Contingencies [Line Items]                    
Approved return on equity     10.90%              
Unfavorable Regulatory Action | Complaint III | Max.                    
Loss Contingencies [Line Items]                    
Approved return on equity     12.19%              
Before Amendment                    
Loss Contingencies [Line Items]                    
Approved return on equity               11.14%    
v3.20.2
Environmental Liabilities (Detail)
$ in Millions
1 Months Ended 9 Months Ended
Apr. 24, 2020
USD ($)
Sep. 11, 2014
USD ($)
Sep. 09, 2011
USD ($)
Nov. 30, 2014
USD ($)
Jul. 31, 2011
USD ($)
site
Sep. 30, 2020
USD ($)
site
Dec. 31, 2019
USD ($)
Aug. 04, 2016
USD ($)
Environmental Exit Cost [Line Items]                
Number of sites with potential remediation obligations | site           26    
Number of sites with liability recorded | site           12    
Number of sits note expected to incur additional liabilities | site           14    
Number of additional sites with liability recorded | site           12    
Number of sites where gas was manufactured in the past | site           53    
Number of sites for which we have entered into consent orders to investigate and remediate | site           41    
Costs related to investigation and remediation           $ 344 $ 349  
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        
Loss contingency, damages sought, value $ 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          
United Illuminating Company (UI)                
Environmental Exit Cost [Line Items]                
Costs related to investigation and remediation           $ 17 16 $ 30
New York State Registry                
Environmental Exit Cost [Line Items]                
Number of sites with potential remediation obligations | site           16    
Number of sites where gas was manufactured in the past | site           6    
Maine's Uncontrolled Sites Program                
Environmental Exit Cost [Line Items]                
Number of sites with potential remediation obligations | site           5    
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           6    
Ten of Twenty-five Sites                
Environmental Exit Cost [Line Items]                
Estimated environmental liability           $ 6    
Another Ten Sites                
Environmental Exit Cost [Line Items]                
Estimated environmental liability           9    
Another Ten Sites | Min.                
Environmental Exit Cost [Line Items]                
Estimated environmental liability           13    
Another Ten Sites | Max.                
Environmental Exit Cost [Line Items]                
Estimated environmental liability           $ 23    
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           $ 96 $ 97  
Manufactured Gas Plants | Min.                
Environmental Exit Cost [Line Items]                
Costs related to investigation and remediation           181    
Manufactured Gas Plants | Max.                
Environmental Exit Cost [Line Items]                
Costs related to investigation and remediation           $ 378    
v3.20.2
Post-Retirement and Similar Obligations - Additional Information (Detail)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
USD ($)
Sep. 30, 2020
USD ($)
Retirement Benefits [Abstract]    
Defined benefit, pension contributions $ 34 $ 59
Additional contributions for remainder of fiscal year $ 25 $ 25
v3.20.2
Post-Retirement and Similar Obligations - Periodic Benefit Costs Net (Detail) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Pension Plan        
Defined Benefit Plan Disclosure [Line Items]        
Service cost $ 12 $ 10 $ 35 $ 30
Interest cost 27 33 81 98
Expected return on plan assets (50) (48) (150) (144)
Prior service costs 0 0 0 (1)
Actuarial loss 31 28 94 85
Net Periodic Benefit Cost 20 23 60 68
Other Postretirement Benefit Plan        
Defined Benefit Plan Disclosure [Line Items]        
Service cost 1 1 2 2
Interest cost 4 4 10 12
Expected return on plan assets (2) (1) (6) (5)
Prior service costs (3) (3) (7) (7)
Actuarial loss 0 0 1 (1)
Net Periodic Benefit Cost $ 0 $ 1 $ 0 $ 1
v3.20.2
Equity - Additional Information (Detail) - USD ($)
$ in Millions
1 Months Ended 3 Months Ended 9 Months Ended
Oct. 31, 2020
May 31, 2018
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Dec. 31, 2019
Class of Stock [Line Items]              
Treasury stock, shares (in shares)     485,597   485,597   485,810
Convertible preferred stock, shares outstanding (in shares)     0   0   0
Release of common stock held in trust (in shares)     0 0 213 0  
Number of shares authorized to be repurchased (in shares)   42,777          
Treasury shares of common stock (in shares)     303,835   303,835    
Repurchases of common stock     $ 14   $ 14   $ 12
Subsequent Event              
Class of Stock [Line Items]              
Release of common stock held in trust (in shares) 4,332            
Iberdrola Renewables Holding, Inc              
Class of Stock [Line Items]              
Percentage of equity owned by parent     81.50%   81.50%    
v3.20.2
Equity - Accumulated Other Comprehensive Gain (Loss) (Detail) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period $ 15,916 $ 15,549 $ 15,586 $ 15,403
Other comprehensive income (loss), net of tax (6) 10 (19) (15)
Balance, end of period 15,854 15,518 15,854 15,518
Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, tax (3) 2 (8) (8)
Reclassification to net income of loss on cash flow hedges, tax expense (benefit) 0 1 1 2
Cumulative Effect, Period of Adoption, Adjustment        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period     (1) (1)
Accumulated Other Comprehensive Loss        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period (108) (109) (95) (72)
Other comprehensive income (loss), net of tax (6) 10 (19) (15)
Balance, end of period (114) (99) (114) (99)
Accumulated Other Comprehensive Loss | Cumulative Effect, Period of Adoption, Adjustment        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period       (12)
Gain on revaluation of defined benefit plans net of tax expense        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period (12) (13) (12) (11)
Other comprehensive income (loss), net of tax 0 0 0 0
Balance, end of period (12) (13) (12) (13)
Gain on revaluation of defined benefit plans net of tax expense | Cumulative Effect, Period of Adoption, Adjustment        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period       (2)
Accumulated defined benefit plans adjustment, net loss attributable to parent        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period (7) (7) (7) (6)
Other comprehensive income (loss), net of tax 0 0 0 (1)
Balance, end of period (7) (7) (7) (7)
Accumulated defined benefit plans adjustment, net loss attributable to parent | Cumulative Effect, Period of Adoption, Adjustment        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period       0
Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period (29) (18) (13) 9
Other comprehensive income (loss), net of tax (15) 5 (31) (22)
Balance, end of period (44) (13) (44) (13)
Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period       0
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]        
Balance, beginning of period (60) (71) (63) (64)
Other comprehensive income (loss), net of tax 9 5 12 8
Balance, end of period (51) (66) (51) (66)
Reclassification to net income of (gains) losses on cash flow hedges, net of income tax (benefit) expense | Cumulative Effect, Period of Adoption, Adjustment        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period       (10)
Gain (loss) on derivative qualifying as cash flow hedges        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period (89) (89) (76) (55)
Other comprehensive income (loss), net of tax (6) 10 (19) (14)
Balance, end of period $ (95) $ (79) $ (95) (79)
Gain (loss) on derivative qualifying as cash flow hedges | Cumulative Effect, Period of Adoption, Adjustment        
AOCI Attributable to Parent, Net of Tax [Roll Forward]        
Balance, beginning of period       $ (10)
v3.20.2
Earnings Per Share (Detail) - USD ($)
$ / shares in Units, $ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Numerator:        
Net income attributable to AVANGRID $ 87 $ 150 $ 415 $ 477
Denominator:        
Weighted average number of shares outstanding - basic (in shares) 309,491,082 309,491,082 309,496,234 309,491,082
Weighted average number of shares outstanding - diluted (in shares) 309,550,126 309,517,778 309,554,838 309,512,301
Earnings per share attributable to AVANGRID        
Earnings Per Common Share, Basic (in usd per share) $ 0.28 $ 0.48 $ 1.34 $ 1.54
Earnings Per Common Share, Diluted (in usd per share) $ 0.28 $ 0.48 $ 1.34 $ 1.54
v3.20.2
Segment Information - Additional Information (Detail)
9 Months Ended
Sep. 30, 2020
segment
Segment Reporting Information [Line Items]  
Number of reportable segments 2
Networks  
Segment Reporting Information [Line Items]  
Number of reportable segments 1
Number of operating segments 8
v3.20.2
Segment Information - Adjusted Net Income (Detail) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Dec. 31, 2019
Segment Reporting Information [Line Items]          
Revenues $ 1,470 $ 1,487 $ 4,651 $ 4,729  
Depreciation and amortization 255 237 748 681  
Operating income 165 239 647 787  
Earnings (losses) from equity method investments 1 (1) (3) 1  
Interest expense, net of capitalization 86 72 251 226  
Income tax expense (benefit) 15 33 21 103  
Adjusted net income 100 123 434 442  
Capital expenditures     1,960 2,045  
Property, plant and equipment 26,432   26,432   $ 25,218
Equity method investments 668   668   645
Total assets 35,640   35,640   34,416
Networks          
Segment Reporting Information [Line Items]          
Revenues 1,197 1,140 3,779 3,837  
Renewables          
Segment Reporting Information [Line Items]          
Revenues 276 347 876 896  
Operating Segments | Networks          
Segment Reporting Information [Line Items]          
Revenues 1,194 1,139 3,775 3,831  
Depreciation and amortization 151 138 446 407  
Operating income 160 182 617 668  
Earnings (losses) from equity method investments 3 3 8 8  
Interest expense, net of capitalization 63 66 199 201  
Income tax expense (benefit) 20 28 75 117  
Adjusted net income 99 89 379 355  
Capital expenditures     1,312 1,086  
Property, plant and equipment 16,640   16,640   15,840
Equity method investments 138   138   139
Total assets 24,178   24,178   23,250
Operating Segments | Renewables          
Segment Reporting Information [Line Items]          
Revenues 275 347 875 896  
Depreciation and amortization 104 98 301 273  
Operating income 7 53 24 115  
Earnings (losses) from equity method investments (2) (4) (11) (7)  
Interest expense, net of capitalization (1) (1) (1) 6  
Income tax expense (benefit) (7) 2 (53) (15)  
Adjusted net income 32 46 108 115  
Capital expenditures     648 959  
Property, plant and equipment 9,782   9,782   9,368
Equity method investments 530   530   506
Total assets 12,694   12,694   13,163
Intersegment Eliminations          
Segment Reporting Information [Line Items]          
Revenues (4) (1) (5) (6)  
Intersegment Eliminations | Networks          
Segment Reporting Information [Line Items]          
Revenues 3 1 4 6  
Intersegment Eliminations | Renewables          
Segment Reporting Information [Line Items]          
Revenues 1 0 1 0  
Corporate And Eliminations          
Segment Reporting Information [Line Items]          
Revenues 1 1 1 2  
Depreciation and amortization 0 1 1 1  
Operating income (2) 4 6 4  
Earnings (losses) from equity method investments 0 0 0 0  
Interest expense, net of capitalization 24 7 53 19  
Income tax expense (benefit) 2 3 (1) 1  
Adjusted net income (31) $ (12) (53) (28)  
Capital expenditures     0 $ 0  
Property, plant and equipment 10   10   10
Equity method investments 0   0   0
Total assets $ (1,232)   $ (1,232)   $ (1,997)
v3.20.2
Segment Information - Reconciliation of Adjusted Net Income to Net Income (Detail) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Segment Reporting [Abstract]        
Adjusted Net Income Attributable to Avangrid, Inc. $ 100 $ 123 $ 434 $ 442
Adjustments:        
Mark-to-market earnings - Renewables (7) 42 9 66
Restructuring charges (1) (2) (5) (4)
Accelerated depreciation from repowering (3) (5) (9) (15)
Impact of COVED -19 (8) 0 (21) 0
Income tax impact of adjustments 5 (9) 7 (12)
Net Income Attributable to Avangrid, Inc. $ 87 $ 150 $ 415 $ 477
v3.20.2
Related Party Transactions - Schedule of Related Party Transactions (Detail) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Iberdrola Renovables Energía, S.L.        
Related Party Transaction [Line Items]        
Purchases From $ (2) $ (1) $ (6) $ (10)
Iberdrola Financiación, S.A.        
Related Party Transaction [Line Items]        
Purchases From (3) (1) (5) (2)
Iberdrola, S.A.        
Related Party Transaction [Line Items]        
Purchases From (10) (8) (31) (28)
Vineyard Wind        
Related Party Transaction [Line Items]        
Sales To 3 4 7 11
Other        
Related Party Transaction [Line Items]        
Sales To 0 0 0 1
Purchases From (1) $ (1) (2) $ (2)
Iberdrola Solutions        
Related Party Transaction [Line Items]        
Sales To $ 2   $ 2  
v3.20.2
Related Party Transactions - Additional Information (Details) - USD ($)
9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Dec. 31, 2019
Related Party Transaction [Line Items]      
Deposit balance $ 0   $ 150,000,000
Iberdrola Solutions      
Related Party Transaction [Line Items]      
Notes payable 4,000,000   0
Affiliated Entity      
Related Party Transaction [Line Items]      
Impairments 0    
Iberdrola Financiacion, S.A.U      
Related Party Transaction [Line Items]      
Line of credit facility, maximum borrowing capacity $ 500,000,000    
Credit facility, commitment fee percentage 0.105%    
Credit facility outstanding amount $ 0   $ 0
Iberdrola, S.A. | Siemens-Gamesa      
Related Party Transaction [Line Items]      
Business acquisition, percentage of voting interests acquired 8.10%    
Related party transaction, amount $ 11,000,000 $ 18,000,000  
v3.20.2
Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($)
$ in Millions
Sep. 30, 2020
Dec. 31, 2019
Related Party Transaction [Line Items]    
Owed By   $ 1
Iberdrola, S.A.    
Related Party Transaction [Line Items]    
Owed By $ 1  
Owed To (32) (42)
Iberdrola Renovables Energía, S.L.    
Related Party Transaction [Line Items]    
Owed To (6) 0
Iberdrola Financiación, S.A.    
Related Party Transaction [Line Items]    
Owed To (4) 0
Vineyard Wind    
Related Party Transaction [Line Items]    
Owed By 3 5
Iberdrola Solutions    
Related Party Transaction [Line Items]    
Owed By 2 0
Owed To (4)  
Siemens-Gamesa    
Related Party Transaction [Line Items]    
Owed To   (18)
Other    
Related Party Transaction [Line Items]    
Owed By 1 4
Owed To $ (1) $ (4)
v3.20.2
Other Financial Statement Items - Accounts Receivable and Unbilled Revenue (Details) - USD ($)
$ in Millions
Sep. 30, 2020
Dec. 31, 2019
Balance Sheet Related Disclosures [Abstract]    
Trade receivables and unbilled revenues $ 1,115 $ 1,151
Allowance for credit losses (94) (69)
Accounts receivable and unbilled revenues, net $ 1,021 $ 1,082
v3.20.2
Other Financial Statement Items - Allowance For Credit Losses (Details) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Accounts Receivable, Allowance for Credit Loss [Roll Forward]        
Beginning balance $ 94 $ 73 $ 94 $ 73
Current period provision 19 24 60 71
Write-off as uncollectible (10) (24) (35) (60)
Ending balance $ 85 $ 73 $ 69 $ 62
v3.20.2
Other Financial Statement Items - Additional Information (Detail) - USD ($)
3 Months Ended 9 Months Ended
Jun. 29, 2020
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Sep. 25, 2020
Sep. 01, 2020
Jul. 24, 2020
Jun. 30, 2020
May 01, 2020
Apr. 09, 2020
Dec. 31, 2019
Jun. 30, 2019
Dec. 31, 2018
Supplemental Balance Sheet Information [Line Items]                            
Allowance for doubtful accounts, deferred payment arrangement   $ 94,000,000 $ 73,000,000 $ 94,000,000 $ 73,000,000       $ 85,000,000     $ 69,000,000 $ 73,000,000 $ 62,000,000
Provision for doubtful accounts, accounts receivable   19,000,000 24,000,000 60,000,000 71,000,000                  
Prepaid other taxes   179,000,000   179,000,000               123,000,000    
Notes payable   998,000,000   998,000,000               560,000,000    
South Dakota Wind Farm | Disposed of by Sale                            
Supplemental Balance Sheet Information [Line Items]                            
Percentage of ownership transferred               85.00%            
Consideration from disposition               $ 236,000,000            
Assets held for sale from disposition   196,000,000   $ 196,000,000                    
2020 Credit Facility | Revolving Credit Facility                            
Supplemental Balance Sheet Information [Line Items]                            
Line of credit facility, maximum borrowing capacity $ 500,000,000                          
Credit facility, commitment fee percentage 0.20%                          
Debt extension term 1 year     1 year                    
Debt extension cost (in basis points) 0.75%                          
2020 Credit Facility | Min. | Revolving Credit Facility                            
Supplemental Balance Sheet Information [Line Items]                            
Credit facility, commitment fee percentage 0.15%                          
2020 Credit Facility | Max. | Revolving Credit Facility                            
Supplemental Balance Sheet Information [Line Items]                            
Credit facility, commitment fee percentage 0.30%                          
Commercial Paper                            
Supplemental Balance Sheet Information [Line Items]                            
Notes payable   999,000,000   $ 999,000,000               562,000,000    
Senior Notes | Unsecured Notes Maturing in 2025                            
Supplemental Balance Sheet Information [Line Items]                            
Face amount of debt                     $ 750,000,000      
Interest rate                     3.20%      
Senior Notes | Pollution Control Bonds Due from 2026 to 2029                            
Supplemental Balance Sheet Information [Line Items]                            
Face amount of debt                   $ 200,000,000        
Senior Notes | Pollution Control Bonds Due from 2026 to 2029 | Min.                            
Supplemental Balance Sheet Information [Line Items]                            
Interest rate                   1.40%        
Senior Notes | Pollution Control Bonds Due from 2026 to 2029 | Max.                            
Supplemental Balance Sheet Information [Line Items]                            
Interest rate                   1.61%        
Senior Notes | Unsecured Notes Maturing in 2050                            
Supplemental Balance Sheet Information [Line Items]                            
Face amount of debt             $ 25,000,000              
Interest rate             3.68%              
Senior Notes | Unsecured Notes Maturing in 2030                            
Supplemental Balance Sheet Information [Line Items]                            
Face amount of debt           $ 200,000,000                
Interest rate           1.95%                
Deferred Payment Arrangements                            
Supplemental Balance Sheet Information [Line Items]                            
Accounts receivable   77,000,000   77,000,000               65,000,000    
Allowance for doubtful accounts, deferred payment arrangement   37,000,000   37,000,000               $ 33,000,000    
Provision for doubtful accounts, accounts receivable   $ 3,000,000 $ 1,000,000 $ 4,000,000 $ 3,000,000                  
v3.20.2
Other Financial Statement Items - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($)
$ in Millions
Sep. 30, 2020
Dec. 31, 2019
Property, plant and equipment    
Accumulated depreciation $ 9,713 $ 9,059
Intangible assets    
Accumulated amortization $ 315 $ 305
v3.20.2
Income Tax Expense (Details)
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Income Tax Disclosure [Abstract]        
Effective income tax rate 15.60% 19.20% 5.10% 18.30%
v3.20.2
Stock-Based Compensation Expense (Detail)
$ / shares in Units, $ in Millions
1 Months Ended 3 Months Ended 9 Months Ended
Mar. 18, 2020
shares
Aug. 31, 2020
$ / shares
shares
Jun. 30, 2020
USD ($)
shares
May 31, 2020
shares
Feb. 29, 2020
shares
Oct. 31, 2018
$ / shares
shares
Jun. 30, 2018
$ / shares
shares
Sep. 30, 2020
USD ($)
Sep. 30, 2019
USD ($)
Sep. 30, 2020
USD ($)
installment
Sep. 30, 2019
USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                      
Stock-based compensation expense | $               $ 1 $ 0 $ 12 $ 2
Restricted Stock Units (RSUs)                      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                      
Number of shares granted (in shares)   5,000       8,000 60,000        
Grant date fair value (in usd per share) | $ / shares   $ 48.99       $ 47.59 $ 50.40        
Number of shares issued (in shares)     60,000                
Cash used to settle award | $     $ 3                
Performance Shares Units (PSUs)                      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                      
Number of shares granted (in shares)         208,268            
Number of shares issued (in shares)       42,777              
Number of shares forfeited (in shares)       2,605              
Performance Shares Units (PSUs) | Officers and Employees                      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                      
Number of installment payments of employee related payables | installment                   3  
Phantom Shares                      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                      
Number of shares granted (in shares) 167,060                    
Cash used to settle award | $     $ 2                
Share based compensation liability | $               $ 2   $ 2  
v3.20.2
Variable Interest Entities (Detail)
$ in Millions
9 Months Ended
May 08, 2020
USD ($)
wind_farm
MW
Mar. 02, 2020
USD ($)
numberOfInvestors
wind_farm
agreement
Sep. 30, 2020
USD ($)
Sep. 30, 2019
USD ($)
Dec. 31, 2019
USD ($)
Variable Interest Entity [Line Items]          
Number of TEF agreements | agreement   2      
Contributions from noncontrolling interests $ 70 $ 237 $ 312 $ 133  
Number of tax equity investors | numberOfInvestors   2      
Wind firms that reached commercial operation | wind_farm 3 2      
Wind farms expected to be part of Aeolus VII | wind_farm 4        
Proposed wind farm and electricity transmission project capacity (MW) | MW 681        
Assets of variable interest entities (VIEs)     35,640   $ 34,416
Liabilities of variable interest entities (VIEs)     19,786   18,830
Variable Interest Entity, Primary Beneficiary          
Variable Interest Entity [Line Items]          
Assets of variable interest entities (VIEs)     1,720   806
Liabilities of variable interest entities (VIEs)     $ 104   $ 29
v3.20.2
Equity Method Investments (Details)
$ in Millions
1 Months Ended 3 Months Ended 9 Months Ended
Oct. 31, 2020
MW
Mar. 31, 2020
MW
Sep. 30, 2020
USD ($)
mi²
MW
Dec. 31, 2019
USD ($)
Schedule of Equity Method Investments [Line Items]        
Production capacity (in MW) | MW     3,000  
Equity method investments     $ 668 $ 645
AC Transmission Public Policy Project, total cost     600  
Amount receivable from equity method investment investee       1
Vineyard Wind, LLC        
Schedule of Equity Method Investments [Line Items]        
Proposed offshore wind farm capacity (in MW) | MW   804    
Equity method investments     261 227
Vineyard Wind, LLC | Subsequent Event | Min.        
Schedule of Equity Method Investments [Line Items]        
Proposed offshore wind farm capacity (in MW) | MW 1,200      
Vineyard Wind, LLC | Subsequent Event | Max.        
Schedule of Equity Method Investments [Line Items]        
Proposed offshore wind farm capacity (in MW) | MW 1,300      
New York TransCo.        
Schedule of Equity Method Investments [Line Items]        
Amount receivable from equity method investment investee     $ 0 $ 0
Renewables | Vineyard Wind, LLC        
Schedule of Equity Method Investments [Line Items]        
Equity method investment, ownership percentage     50.00%  
Contributions to equity method investment     $ 157  
Renewables | Second Offshore Development Project        
Schedule of Equity Method Investments [Line Items]        
Contributions to equity method investment     $ 110  
Networks | New York TransCo.        
Schedule of Equity Method Investments [Line Items]        
Equity method investment, ownership percentage     20.00%  
Contributions to equity method investment     $ 120  
Vineyard Wind, LLC        
Schedule of Equity Method Investments [Line Items]        
Area of land (in square-mile) | mi²     260  
CIP        
Schedule of Equity Method Investments [Line Items]        
Equity method investment, ownership percentage       50.00%
v3.20.2
Restructuring and Severance Related Expenses - Additional Information (Detail) - USD ($)
$ in Millions
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Restructuring Reserve [Roll Forward]        
Beginning Balance     $ 5  
Restructuring and severance related expenses     2  
Payments     (3)  
Ending Balance $ 4   4  
Operations and Maintenance        
Restructuring Reserve [Roll Forward]        
Restructuring and severance related expenses 0 $ 1 2 $ 3
Depreciation And Amortization        
Restructuring Reserve [Roll Forward]        
Restructuring and severance related expenses $ 1 $ 1 $ 3 $ 1
v3.20.2
Subsequent Event (Details) - Subsequent Event - NM Green Holdings, Inc.
Oct. 20, 2020
USD ($)
$ / shares
Subsequent Event [Line Items]  
Merger agreement, share price (in dollars per share) | $ / shares $ 50.30
Merger agreement term, ownership percentage benchmark 15.00%
Merger agreement, termination rights term, extension period 3 months
Merger agreement, termination rights term, termination fees $ 130,000,000
Merger agreement, termination rights term, termination fees as remedy 184,000,000
Merger agreement, termination rights term, termination fees, out-of-pocket fees and expenses reimbursable limit (up to) $ 10,000,000