AVANGRID, INC., 10-Q filed on 5/4/2021
Quarterly Report
v3.21.1
Cover Page - shares
 3 Months Ended
Mar. 31, 2021
Apr. 30, 2021
Cover [Abstract]    
Entity Registrant Name Avangrid, Inc.  
Document Type 10-Q  
Document Quarterly Report true  
Document Period End Date Mar. 31, 2021  
Document Transition Report false  
Entity File Number 001-37660  
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 629-1190  
Title of 12(b) Security Common Stock, par value $0.01 per share  
Trading Symbol AGR  
Security Exchange Name NYSE  
Entity Current Reporting Status Yes  
Entity Interactive Data Current Yes  
Entity Filer Category Large Accelerated Filer  
Entity Small Business false  
Entity Emerging Growth Company false  
Entity Shell Company false  
Entity Common Stock, Shares Outstanding   309,369,894
Amendment Flag false  
Document Fiscal Year Focus 2021  
Document Fiscal Period Focus Q1  
Entity Central Index Key 0001634997  
Current Fiscal Year End Date --12-31  
v3.21.1
Condensed Consolidated Statements of Income (unaudited) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Income Statement [Abstract]    
Operating Revenues $ 1,966 $ 1,789
Operating Expenses    
Purchased power, natural gas and fuel used 501 475
Operations and maintenance 642 570
Depreciation and amortization 247 251
Taxes other than income taxes 170 166
Total Operating Expenses 1,560 1,462
Operating Income 406 327
Other Income and (Expense)    
Other income (expense) 1 (3)
Earnings (losses) from equity method investments 1 (6)
Interest expense, net of capitalization (73) (76)
Income Before Income Tax 335 242
Income tax expense 14 12
Net Income 321 230
Net loss attributable to noncontrolling interests 13 10
Net Income Attributable to Avangrid, Inc. $ 334 $ 240
Earnings Per Common Share, Basic (in dollars per share) $ 1.08 $ 0.78
Earnings Per Common Share, Diluted (in dollars per share) $ 1.08 $ 0.78
Weighted-average Number of Common Shares Outstanding:    
Basic (in shares) 309,495,250 309,491,082
Diluted (in shares) 309,736,266 309,623,573
v3.21.1
Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Statement of Comprehensive Income [Abstract]    
Net Income $ 321 $ 230
Other Comprehensive Income (Loss)    
Unrealized loss during the period on derivatives qualifying as cash flow hedges, net of income tax of $(5) and $(8), respectively (27) (23)
Reclassification to net income of loss on cash flow hedges, net of income taxes $(1) and $0, respectively 1 2
Other Comprehensive Income (Loss) (26) (21)
Comprehensive Income 295 209
Net loss attributable to noncontrolling interests 13 10
Comprehensive Income Attributable to Avangrid, Inc. $ 308 $ 219
v3.21.1
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Statement of Comprehensive Income [Abstract]    
Unrealized (loss) gain during the period on derivatives qualifying as cash flow hedges, tax $ (5) $ (8)
Reclassification to net income of loss on cash flow hedges, tax expense (benefit) $ (1) $ 0
v3.21.1
Condensed Consolidated Balance Sheets (unaudited) - USD ($)
$ in Millions
Mar. 31, 2021
Dec. 31, 2020
Current Assets    
Cash and cash equivalents $ 813 $ 1,463
Accounts receivable and unbilled revenues, net 1,283 1,187
Accounts receivable from affiliates 15 12
Derivative assets 23 18
Fuel and gas in storage 83 93
Materials and supplies 171 169
Prepayments and other current assets 534 525
Regulatory assets 317 310
Total Current Assets 3,239 3,777
Total Property, Plant and Equipment ($1,637 related to VIEs) 27,168 26,751
Operating lease right-of-use assets 177 153
Equity method investments 695 668
Other investments 61 68
Regulatory assets 2,583 2,572
Other Assets    
Goodwill 3,119 3,119
Intangible assets 302 305
Derivative assets 74 79
Other 350 331
Total Other Assets 3,845 3,834
Total Assets 37,768 37,823
Current Liabilities    
Current portion of debt 387 313
Notes payable 0 307
Notes payable to affiliates 8 0
Interest accrued 81 70
Accounts payable and accrued liabilities 1,416 1,453
Accounts payable to affiliates 16 50
Dividends payable 136 136
Taxes accrued 60 73
Operating lease liabilities 16 8
Derivative liabilities 32 17
Other current liabilities 348 368
Regulatory liabilities 292 274
Total Current Liabilities 2,792 3,069
Regulatory liabilities 3,150 3,137
Other Non-current Liabilities    
Deferred income taxes 1,924 1,919
Deferred income 1,181 1,204
Pension and other postretirement 979 1,007
Operating lease liabilities 172 154
Derivative liabilities 85 79
Asset retirement obligations 217 210
Environmental remediation costs 284 292
Other 591 448
Total Other Non-current Liabilities 5,433 5,313
Non-current debt 7,401 7,478
Non-current debt to affiliate 3,000 3,000
Total Non-current Liabilities 18,984 18,928
Total Liabilities 21,776 21,997
Commitments and Contingencies
Stockholders’ Equity:    
Common stock, $.01 par value, 500,000,000 shares authorized, 309,848,228 and 309,794,917 shares issued; 309,369,894 and 309,077,300 shares outstanding, respectively 3 3
Additional paid in capital 13,667 13,665
Treasury stock (16) (14)
Retained earnings 1,864 1,666
Accumulated other comprehensive loss (137) (111)
Total Stockholders’ Equity 15,381 15,209
Non-controlling interests 611 617
Total Equity 15,992 15,826
Total Liabilities and Equity $ 37,768 $ 37,823
v3.21.1
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($)
$ in Millions
Mar. 31, 2021
Dec. 31, 2020
Property, plant and equipment $ 27,168 $ 26,751
Common stock, par value (in dollars per share) $ 0.01 $ 0.01
Common stock, authorized (in shares) 500,000,000 500,000,000
Common stock, issued (in shares) 309,848,228 309,794,917
Common stock, outstanding (in shares) 309,369,894 309,077,300
Variable Interest Entity, Primary Beneficiary    
Property, plant and equipment $ 1,637 $ 1,637
v3.21.1
Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Cash Flow from Operating Activities:    
Net Income $ 321 $ 230
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization 247 251
Regulatory assets/liabilities amortization and carrying cost 21 18
Pension cost 17 20
(Earnings) losses from equity method investments (1) 6
Distributions of earnings received from equity method investments 4 3
Unrealized loss (gain) on marked-to-market derivative contracts 53 (18)
Deferred taxes (13) 10
Other non-cash items (5) 1
Changes in operating assets and liabilities:    
Current assets (169) (16)
Noncurrent assets (93) (55)
Current liabilities 39 (117)
Noncurrent liabilities 4 (26)
Net Cash Provided by Operating Activities 425 307
Cash Flow from Investing Activities:    
Capital expenditures (623) (742)
Contributions in aid of construction 9 7
Proceeds from sale of assets 8 6
Proceeds from notes receivable from affiliates 5 2
Distributions received from equity method investments 1 1
Other investments and equity method investments, net (39) (23)
Net Cash Used in Investing Activities (639) (749)
Cash Flow from Financing Activities:    
Repayments of non-current debt (2) (3)
(Repayments) receipts of other short-term debt, net (301) 187
Repayments of financing leases (1) (1)
Repurchase of common stock (2) 0
Issuance of common stock (1) 0
Distributions to noncontrolling interests (3) (1)
Contributions from noncontrolling interests 10 244
Dividends paid (136) (136)
Net Cash (Used in) Provided by Financing Activities (436) 290
Net Decrease in Cash, Cash Equivalents and Restricted Cash (650) (152)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period 1,467 184
Cash, Cash Equivalents and Restricted Cash, End of Period 817 32
Supplemental Cash Flow Information    
Cash paid for interest, net of amounts capitalized 51 70
Cash paid for income taxes $ 4 $ 2
v3.21.1
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
Total Stockholders’ Equity
Total Stockholders’ Equity
Cumulative Effect, Period of Adoption, Adjustment
Noncontrolling Interests
Balance, beginning of period (in shares) at Dec. 31, 2019 [1]     309,005,272                
Balance, beginning of period at Dec. 31, 2019 $ 15,539 $ (1) $ 3 $ 13,660 $ (12) $ 1,634 $ (1) $ (95) $ 15,190 $ (1) $ 349
Increase (Decrease) in Stockholders' Equity [Roll Forward]                      
Net income (loss) 230         240     240   (10)
Other comprehensive loss, net of tax (21)             (21) (21)    
Comprehensive Income 209                    
Dividends declared (136)         (136)     (136)    
Release of common stock held in trust (in shares) [1]     213                
Stock-based compensation 7     7         7    
Distributions to noncontrolling interests (1)                   (1)
Contributions from noncontrolling interests 244                   244
Balance, end of period (in shares) at Mar. 31, 2020 [1]     309,005,485                
Balance, end of period at Mar. 31, 2020 $ 15,861   $ 3 13,667 (12) 1,737   (116) 15,279   582
Balance, beginning of period (in shares) at Dec. 31, 2020 309,077,300   309,077,300 [1]                
Balance, beginning of period at Dec. 31, 2020 $ 15,826   $ 3 13,665 (14) 1,666   (111) 15,209   617
Increase (Decrease) in Stockholders' Equity [Roll Forward]                      
Net income (loss) 321         334     334   (13)
Other comprehensive loss, net of tax (26)             (26) (26)    
Comprehensive Income 295                    
Dividends declared (136)         (136)     (136)    
Release of common stock held in trust (in shares) [1]     292,594                
Issuances of common stock (in shares) [1]     53,311                
Issuance of common stock (1)     (1)         (1)    
Repurchase of common stock (in shares) [1]     (53,311)                
Repurchase of common stock (2)       (2)       (2)    
Stock-based compensation 3     3         3    
Distributions to noncontrolling interests (3)                   (3)
Contributions from noncontrolling interests $ 10                   10
Balance, end of period (in shares) at Mar. 31, 2021 309,369,894   309,369,894 [1]                
Balance, end of period at Mar. 31, 2021 $ 15,992   $ 3 $ 13,667 $ (16) $ 1,864   $ (137) $ 15,381   $ 611
[1] (*) Par value of share amounts is $0.01
v3.21.1
Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Statement of Stockholders' Equity [Abstract]    
Other comprehensive loss, tax $ (6) $ (8)
Dividends declared (in dollars per share) $ 0.44 $ 0.44
Common stock, par value (in dollars per share) $ 0.01 $ 0.01
v3.21.1
Background and Nature of Operations
 3 Months Ended
Mar. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Background and Nature of Operations Background and Nature of Operations
Avangrid, 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. 
Proposed Merger with PNMR
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 is expected to 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 Federal Energy Regulatory Commission (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. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. During the period ended March 31, 2021, the Merger obtained regulatory approval under the the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approvals from the CFIUS and the FCC. During April 2021, the Merger received approval from the FERC. The Merger is currently expected to close in the second half 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 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 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.
On April 15, 2021, AVANGRID entered into a side letter agreement with Iberdrola, which sets forth certain terms and conditions relating to the funding commitment letter (the Side Letter Agreement). The Side Letter Agreement provides that any drawing in the form of indebtedness made by the Corporation pursuant to the Funding Commitment Letter shall bear interest at
an interest rate equal to 3-month LIBOR plus 0.75% per annum calculated on the basis 360-day year for the actual number of days elapsed and, commencing on the date of the Funding Commitment Letter, we shall pay Iberdrola a facility fee equal to 0.12% per annum on the undrawn portion of the funding commitment set forth in the Funding Commitment Letter.
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).
v3.21.1
Basis of Presentation
 3 Months Ended
Mar. 31, 2021
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, 2020.
The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts 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 have been 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 months ended March 31, 2021, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2021.
v3.21.1
Significant Accounting Policies and New Accounting Pronouncements
 3 Months Ended
Mar. 31, 2021
Accounting Policies [Abstract]  
Significant Accounting Policies and New Accounting Pronouncements Significant Accounting Policies and New Accounting Pronouncements
The new accounting pronouncements we have adopted as of January 1, 2021, 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, 2020, except for those described below resulting from the adoption of new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB).
Adoption of New Accounting Pronouncements
(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. We adopted the amendments effective January 1, 2021, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. We are applying the amendments on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment requirement.
Accounting Pronouncements Issued but Not Yet Adopted
The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2020, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.
(a) Facilitation of the effects of reference rate reform on financial reporting, and subsequent scope clarification
In March 2020, the FASB issued amendments and created ASC 848 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.
In January 2021, the FASB issued amendments to clarify the scope of ASC 848 and respond to questions from stakeholders about whether ASC 848 can be applied to derivative instruments that do not reference a rate that is expected to be discontinued but that use an interest rate for margining, discounting, or contract price alignment that is modified because of reference rate reform. The modification, commonly referred to as the “discounting transition,” may have accounting implications, raising concerns about the need to reassess previous accounting determinations related to those derivatives and about the possible hedge accounting consequences of the discounting transition. The amendments clarify that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition, capture the incremental consequences of the scope clarification and tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments are effective immediately, and may be elected retrospectively to eligible modifications as of any date from the beginning of the interim period that includes March 12, 2020, or prospectively to new modifications made on or after any date within the interim period that includes January 7, 2021.
We expect our adoption of reference rate reform and the subsequent scope clarification will not materially affect our consolidated results of operations, financial position and cash flows.
v3.21.1
Revenue
 3 Months Ended
Mar. 31, 2021
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. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. They traditionally invoice their customers by applying approved base rates to usage. 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 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. Contract assets totaled $9 million at both March 31, 2021 and December 31, 2020, 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 $5 million and $9 million at March 31, 2021 and December 31, 2020, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $4 million and $5 million as revenue during the three months ended March 31, 2021 and 2020, respectively.
Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2021 and 2020 are as follows:
Three Months Ended March 31, 2021
 NetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity
$942 $— $— $942 
Regulated operations – natural gas
564 — — 564 
Nonregulated operations – wind
— 371 — 371 
Nonregulated operations – solar
— 4 — 4 
Nonregulated operations – thermal
— 12 — 12 
Other(a)10 32 — 42 
Revenue from contracts with customers
1,516 419 — 1,935 
Leasing revenue2 — — 2 
Derivative revenue — (31)— (31)
Alternative revenue programs
47 — — 47 
Other revenue8 5 — 13 
Total operating revenues
$1,573 $393 $— $1,966 
Three Months Ended March 31, 2020
NetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity
$873 $— $— $873 
Regulated operations – natural gas
507 — — 507 
Nonregulated operations – wind
— 211 — 211 
Nonregulated operations – solar
— 4 — 4 
Nonregulated operations – thermal
— 10 — 10 
Other(a)19 28 — 47 
Revenue from contracts with customers
1,399 253 — 1,652 
Leasing revenue1 — — 1 
Derivative revenue — 70 — 70 
Alternative revenue programs
56 — — 56 
Other revenue5 5 — 10 
Total operating revenues
$1,461 $328 $— $1,789 
(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 March 31, 2021 and December 31, 2020, accounts receivable balances related to contracts with customers were approximately $1,222 million and $1,151 million, respectively, including unbilled revenues of $292 million and $341 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.
As of March 31, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:
As of March 31, 202120222023202420252026ThereafterTotal
(Millions)       
Revenue expected to be recognized on multiyear retail energy sales contracts in place
$6 $1 $1 $— $— $— $8 
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
24 16 14 12 7 68 141 
Revenue expected to be recognized on multiyear renewable energy credit sale contracts
30 18 6 3 3 2 62 
Total operating revenues$60 $35 $21 $15 $10 $70 $211 
As of March 31, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2021 was $69 million.
v3.21.1
Regulatory Assets and Liabilities
 3 Months Ended
Mar. 31, 2021
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. As of March 31, 2021, the total net amount of these items is approximately $1,473 million.
CMP Distribution 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 7.00%, based on an allowed ROE of 9.25% and a 50.00% 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 rolling average period of 18 months, which commenced on March 1, 2020. CMP is meeting the required rolling average benchmarks for all four of these quality measures and expects to file with the MPUC in the third quarter of 2021 to remove the management efficiency adjustment.
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 customers. The management audit was commenced in July 2020 by the MPUC’s consultants and is expected to conclude in 2021.
NYSEG and RG&E Rate Plans
On November 19, 2020, the NYPSC approved a new three-year rate plan for NYSEG & RG&E (2020 Joint Proposal), with modifications to the rate increases at the two electric businesses. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. 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 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. The 2020 Joint Proposal bases delivery revenues on an 8.80% ROE and 48.00% equity ratio; however, for the proposed earnings sharing mechanism, the equity ratio is the lower of the actual equity ratio or 50.00%. The below table provides a summary of
the approved 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$344.6 %$46 5.9 %$36 4.2 %
NYSEG Gas$—— %$2 0.8 %$3 1.6 %
RG&E Electric$173.8 %$14 3.2 %$16 3.3 %
RG&E Gas$—— %$— — %$2 1.3 %
UI, CNG, SCG and BGC Rate Plans
In 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, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50.00% 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 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism, 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 an equity ratio of approximately 52.00%. 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 2018, PURA approved new tariffs for Connecticut Natural Gas Corporation (CNG) effective January 1, 2019 for a three-year rate plan with annual rate increases. 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.
In 2019, the Massachusetts Department of Public Utilities (DPU) approved new distribution rates for BGC. The distribution rate increase is based on a 9.70% ROE and 54.00% 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 Energy 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.
Pursuant to the legislation, on October 30, 2020, PURA reopened a docket related to new rate design and review, expanding the scope to consider the implementation of an (a) interim rate decrease; (b) low income rates; and (c) economic development rates. Seperately, UI was due to make its annual rate adjustment mechanism (RAM) filing on March 8, 2021 for the approval of its RAM Rate Components reconciliations: Generation Services Charges, By-passable Federally Mandated Congestion Costs, System Benefits Charge, Transmission Adjustment Charge and RDM. PURA had previously delayed implementation of those rates for a year in 2020.
On March 9, 2021, UI, jointly with the Office of the CT Attorney General, the Office of CT Consumer Counsel, DEEP and PURA’s Office of Education, Outreach, and Enforcement entered into a settlement agreement and filed a motion to approve the settlement agreement which addressed issues in both dockets.
On April 14, 2021, PURA issued a draft decision which declined to approve the settlement agreement. UI filed written exceptions and held oral arguments. As a result, on April 26, 2021, PURA issued an order suspending the procedural schedule for a period up to and including July 2, 2021, so that the parties to the Settlement could address certain issues PURA identified
in the order. A revised procedural schedule will be issued at a later date. We cannot predict the outcome of these proceedings, including the potential impact on the recovery of UI’s RAM components or the interim rate reduction proceeding.
PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation
On August 6, 2020, the PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15 basis point to UI’s ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. We cannot predict the final outcome of this investigation or potential penalties that may be assessed.
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 March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(Millions)
Pension and other post-retirement benefits cost deferrals$99 $105 
Pension and other post-retirement benefits902 927 
Storm costs460 451 
Rate adjustment mechanism 50 33 
Revenue decoupling mechanism71 58 
Transmission revenue reconciliation mechanism36 31 
Contracts for differences85 86 
Hardship programs15 20 
Plant decommissioning2 3 
Deferred purchased gas4 30 
Deferred transmission expense26 26 
Environmental remediation costs247 247 
Debt premium80 83 
Unamortized losses on reacquired debt25 26 
Unfunded future income taxes382 373 
Federal tax depreciation normalization adjustment146 148 
Asset retirement obligation21 21 
Deferred meter replacement costs36 33 
COVID-19 cost recovery11
Other212 180 
Total regulatory assets2,900 2,882 
Less: current portion317 310 
Total non-current regulatory assets$2,583 $2,572 
“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. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.
“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 unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. A portion of this balance is amortized through current rates, and the remaining portion will be determined through future rate cases.
“Rate adjustment mechanism” represents an interim rate change to return or collect certain defined reconciled revenues and costs for NYSEG and RG&E following the approval of the Joint Proposal by the NYPSC. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve-month period.
“Reliability support services” represents the difference between actual expenses for reliability support services and the amount provided in rates.
"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” 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 forty-six 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 25 to 35 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 or are planned to be 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 excess generation service charge, hedge losses and deferred property tax.
Regulatory liabilities as of March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(Millions)
Energy efficiency portfolio standard$51 $58 
Gas supply charge and deferred natural gas cost9 3 
Pension and other post-retirement benefits cost deferrals57 59 
Carrying costs on deferred income tax bonus depreciation32 34 
Carrying costs on deferred income tax - Mixed Services 263(a)10 11 
2017 Tax Act1,417 1,435 
Rate Change Levelization82 55 
Revenue decoupling mechanism8 9 
Accrued removal obligations1,190 1,184 
Asset sale gain account5 7 
Economic development28 28 
Positive benefit adjustment28 30 
Theoretical reserve flow thru impact9 10 
Deferred property tax29 31 
Net plant reconciliation19 20 
Debt rate reconciliation60 63 
Rate refund – FERC ROE proceeding33 33 
Transmission congestion contracts23 22 
Merger-related rate credits13 14 
Accumulated deferred investment tax credits24 25 
Asset retirement obligation18 18 
Earning sharing provisions16 17 
Middletown/Norwalk local transmission network service collections18 18 
Low income programs31 28 
Non-firm margin sharing credits17 14 
New York 2018 winter storm settlement8 9 
Other207 176 
Total regulatory liabilities3,442 3,411 
Less: current portion292 274 
Total non-current regulatory liabilities$3,150 $3,137 
“Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount 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 three years and began in 2020.
"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 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. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.
“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 three years and began in 2020.
"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 three years and began in 2020.
“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.
"Rate change levelization" adjusts the New York delivery rate increases across the three-year plan to avoid unnecessary spikes and offsetting dips in customer 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 2020.
"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 in current rates is three years for NYSEG and two years for RG&E and began in 2020.
“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 three years and began in 2020.
“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 three years and began in 2020.
“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 three to five years and began in 2020.
"Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided for 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 2020.
"Net plant reconciliation" represents the reconciliation of the actual electric and gas net plant and book depreciation to the targets set forth in the 2020 Joint Proposal. 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 2020.
"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 the Nine Mile 2 Nuclear Plant transmission congestion contract at RG&E. 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 2020.
“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During both the three months ended March 31, 2021 and 2020, $1 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 earnings sharing threshold. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.
"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 NYPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. The balance is being amortized through current rates over an amortization period of three years, beginning in 2020.
“Other” includes cost of removal being amortized through rates and various items subject to reconciliation.
v3.21.1
Fair Value of Financial Instruments and Fair Value Measurements
 3 Months Ended
Mar. 31, 2021
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, fixed income 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, the short-term investment from the proceeds of the Iberdrola Loan, 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 $4 million as of both March 31, 2021 and December 31, 2020, and is included in "Other Assets" on our condensed consolidated balance sheets.
The financial instruments measured at fair value as of March 31, 2021 and December 31, 2020, respectively, consisted of:
As of March 31, 2021Level 1Level 2Level 3NettingTotal
(Millions)     
Equity investments with readily determinable fair values$43 $14 $— $— $57 
Derivative assets
Derivative financial instruments - power$7 $27 $101 $(53)$82 
Derivative financial instruments - gas— 23 17 (27)13 
Contracts for differences — — 2 — 2 
Total$7 $50 $120 $(80)$97 
Derivative liabilities
Derivative financial instruments - power$(20)$(66)$(31)$93 $(24)
Derivative financial instruments - gas(1)(5)(1)6 (1)
Contracts for differences — — (87)— (87)
Derivative financial instruments – Other— (5)— — (5)
Total$(21)$(76)$(119)$99 $(117)
As of December 31, 2020Level 1Level 2Level 3NettingTotal
(Millions)     
Equity investments with readily determinable fair values$49 $14 $— $— $63 
Derivative assets
Derivative financial instruments - power$5 $31 $105 $(54)$87 
Derivative financial instruments - gas— 24 19 (35)8 
Contracts for differences— — 2 — 2 
Total$5 $55 $126 $(89)$97 
Derivative liabilities
Derivative financial instruments - power$(23)$(31)$(23)$72 $(5)
Derivative financial instruments - gas(1)(9)(2)9 (3)
Contracts for differences— — (88)— (88)
Total$(24)$(40)$(113)$81 $(96)
The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2021 and 2020, respectively, is as follows:
Three Months Ended March 31,
(Millions)20212020
Fair Value Beginning of Period,$13 $25 
Gains recognized in operating revenues11 13 
(Losses) recognized in operating revenues(4)(10)
Total gains recognized in operating revenues7 3 
Gains recognized in OCI1 1 
(Losses) recognized in OCI(17)(5)
Total gains (losses) recognized in OCI(16)(4)
Net change recognized in regulatory assets and liabilities1 (3)
Settlements(4)(6)
Fair Value as of March 31,$1 $15 
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
$7 $3 
Level 3 Fair Value Measurement
The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives.
As of March 31, 2021  
IndexAvg.Max.Min.
NYMEX ($/MMBtu)$2.59 $3.47 $1.48 
AECO ($/MMBtu)$1.58 $3.24 $(0.17)
Ameren ($/MWh)$26.21 $40.53 $14.73 
COB ($/MWh)$33.68 $120.68 $8.20 
ComEd ($/MWh)$24.14 $39.26 $12.65 
ERCOT N hub ($/MWh)$32.00 $196.95 $11.25 
ERCOT S hub ($/MWh)$32.26 $203.37 $11.41 
Indiana hub ($/MWh)$28.24 $43.58 $16.36 
Mid C ($/MWh)$29.96 $95.00 $4.00 
Minn hub ($/MWh)$22.79 $37.78 $11.52 
NoIL hub ($/MWh)$24.02 $39.01 $12.70 
PJM W hub ($/MWh)$28.19 $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 considered the measurement uncertainty regarding 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 InputMarch 31, 2021
Risk of non-performance
0.39% - 0.54%
Discount rate
0.35% - 0.92%
Forward pricing ($ per KW-month)
$2.00 - $5.30
Fair Value of Debt
As of March 31, 2021 and December 31, 2020, debt consisted of the Iberdrola Loan (see Note 14), first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt was $11,607 million and $12,166 million as of March 31, 2021 and December 31, 2020, 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.
v3.21.1
Derivative Instruments and Hedging
 3 Months Ended
Mar. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Instruments and Hedging Derivative Instruments and HedgingOur operating and financing 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 March 31, 2021 and December 31, 2020, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:
As of March 31, 2021Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)    
Not designated as hedging instruments    
Derivative assets$6 $4 $6 $2 
Derivative liabilities(6)(2)(30)(78)
— 2 (24)(76)
Designated as hedging instruments
Derivative assets— — — — 
Derivative liabilities— — (4)(1)
— — (4)(1)
Total derivatives before offset of cash collateral— 2 (28)(77)
Cash collateral receivable — — 11 2 
Total derivatives as presented in the balance sheet
$— $2 $(17)$(75)
As of December 31, 2020Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)    
Not designated as hedging instruments    
Derivative assets$3 $5 $3 $3 
Derivative liabilities(3)(4)(34)(78)
— 1 (31)(75)
Designated as hedging instruments
Derivative assets— — — — 
Derivative liabilities— — (1)— 
— — (1)— 
Total derivatives before offset of cash collateral— 1 (32)(75)
Cash collateral receivable— — 18 1 
Total derivatives as presented in the balance sheet$— $1 $(14)$(74)
The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2021 and December 31, 2020, respectively, consisted of:
 March 31,December 31,
As of20212020
(Millions)  
Wholesale electricity purchase contracts (MWh)5.2 5.6 
Natural gas purchase contracts (Dth)8.2 9.5 
Fleet fuel purchase contracts (Gallons)2.6 2.5 
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 our 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 March 31, 2021 and December 31, 2020 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2021 and 2020 are as follows:
(Millions)Loss or Gain Recognized in Regulatory Assets/LiabilitiesLocation of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into IncomeLoss (Gain) Reclassified from Regulatory Assets/Liabilities into Income
As ofThree Months Ended March 31,
March 31, 2021ElectricityNatural Gas2021 ElectricityNatural Gas
Regulatory assets$13 $— Purchased power, natural gas and fuel used$2 $(1)
December 31, 20202020 
Regulatory assets$17 $1 Purchased power, natural gas and fuel used$21 $5 
Pursuant to a PURA order, UI and Connecticut’s other electric utility, The Connecticut Light and Power Company (CL&P), each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers.
PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of March 31, 2021, 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 $85 million, a gross derivative liability of $87 million ($84 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, 2020, 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 $86 million, a gross derivative liability of $88 million ($85 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0.
The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2021 and 2020, respectively, were as follows:
Three Months Ended March 31,
 20212020
(Millions)  
Derivative assets$— $— 
Derivative liabilities$1 $(3)
Derivatives designated as hedging instruments
The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,Gain (Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2021
Interest rate contracts$— Interest expense$1 $73 
Commodity contracts1 Purchased power, natural gas and fuel used— 501 
Foreign currency exchange contracts
(4)— 
Total$(3)$1 
2020
Interest rate contracts$— Interest expense$1 $76 
Commodity contracts(2)Purchased power, natural gas and fuel used— 475 
Foreign currency exchange contracts
(6)— 
Total$(8)$1 
(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 $50 million and $51 million as of March 31, 2021 and December 31, 2020, respectively. For both the three months ended March 31, 2021 and 2020, Networks recorded net derivative losses related to discontinued cash flow hedges of $1 million. Networks will amortize approximately $3 million of discontinued cash flow hedges for the remainder of 2021.
Unrealized losses of $4 million on hedge derivatives are reported in OCI because the forecasted transactions are considered to be probable as of March 31, 2021. Networks expects $0 of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which Networks hedges its exposure to the variability in future cash flows for forecasted fleet fuel transactions is 12 months.
(b) Renewables activities
Renewables sells fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. Renewables also purchases fixed-price gas and basis swaps and sells fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets and enters into tolling arrangements to sell the output of its 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 March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(MWh/Dth in millions)  
Wholesale electricity purchase contracts3 3 
Wholesale electricity sales contracts7 7 
Natural gas and other fuel purchase contracts24 24 
Financial power contracts12 12 
Basis swaps – purchases32 35 
Basis swaps – sales2 2 
The fair values of derivative contracts associated with Renewables' activities as of March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(Millions)  
Wholesale electricity purchase contracts$21 $4 
Wholesale electricity sales contracts(30)11 
Natural gas and other fuel purchase contracts13 — 
Financial power contracts67 66 
Basis swaps – purchases— 7 
Total$71 $88 
The tables below present Renewables' derivative positions as of March 31, 2021 and December 31, 2020, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:
As of March 31, 2021Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets$37 $82 $19 $10 
Derivative liabilities(5)(2)(39)(14)
32 80 (20)(4)
Designated as hedging instruments
Derivative assets2 1 2 14 
Derivative liabilities(6)(1)(12)(23)
(4)— (10)(9)
Total derivatives before offset of cash collateral28 80 (30)(13)
Cash collateral (payable) receivable(5)(8)16 3 
Total derivatives as presented in the balance sheet $23 $72 $(14)$(10)
As of December 31, 2020Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets$47 $89 $2 $9 
Derivative liabilities(23)(2)(4)(11)
24 87 (2)(2)
Designated as hedging instruments
Derivative assets8 15 2 7 
Derivative liabilities(5)(6)(3)(10)
3 9 (1)(3)
Total derivatives before offset of cash collateral27 96 (3)(5)
Cash collateral payable(9)(18)— — 
Total derivatives as presented in the balance sheet$18 $78 $(3)$(5)
Derivatives not designated as hedging instruments
The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2021, consisted of:
Three Months Ended March 31, 2021
TradingNon-tradingTotal amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts$7 $— 
Wholesale electricity sales contracts— (17)
Financial power contracts(5)(16)
Financial and natural gas contracts— (4)
Total gain (loss) included in operating revenues$2 $(37)$1,966 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts$— $10 
Financial power contracts— 1 
Financial and natural gas contracts— 4 
Total gain included in purchased power, natural gas and fuel used$— $15 $501 
Total Gain (Loss) $2 $(22)
The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2020, consisted of:
Three Months Ended March 31, 2020
TradingNon-tradingTotal amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts$(1)$— 
Wholesale electricity sales contracts4 11 
Financial power contracts— 22 
Total gain included in operating revenues$3 $33 $1,789 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts$— $(11)
Financial power contracts— (6)
Financial and natural gas contracts— (2)
Total loss included in purchased power, natural gas and fuel used$— $(19)$475 
Total Gain$3 $14 
Derivatives designated as hedging instruments
The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,(Loss) Gain Recognized in OCI on Derivatives (a)Location of (Gain) Reclassified from Accumulated OCI into Income(Gain) Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2021
Commodity contracts$(28)Operating revenues$(3)$1,966 
2020
Commodity contracts$7 Operating revenues$— $1,789 
(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 $13 million of losses included in accumulated OCI at March 31, 2021, 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 months ended March 31, 2021 and 2020.
(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.
As of March 31, 2021 and December 31, 2020, the net loss in accumulated OCI related to previously settled interest rate contracts was $55 million and $57 million, respectively. For the three months ended March 31, 2021 and 2020, we amortized into income $2 million and $1 million, respectively, of the loss related to settled interest rate contracts. We will amortize approximately $7 million of the net loss on the interest rate contracts for the remainder of 2021.
The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,(Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2021
Interest rate contracts$— Interest expense$2 $73 
2020
Interest rate contracts$(31)Interest expense$1 $76 
(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 which end in 2025 and 2029.
(d) Counterparty credit risk management
NYSEG and RG&E face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are applicable based on the respective counterparty’s or the counterparty guarantor’s credit rating, as provided by Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold.
The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit rating on senior debt were to fall below investment grade. If such an event had occurred as of March 31, 2021, UI would have had to post an aggregate of approximately $16 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. As of March 31, 2021 and December 31, 2020, the amount of cash collateral under master netting arrangements that have not been offset against net derivative positions was $24 million and $18 million, 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 March 31, 2021 was $13 million, for which we have posted collateral.
v3.21.1
Contingencies
 3 Months Ended
Mar. 31, 2021
Commitments and Contingencies Disclosure [Abstract]  
Contingencies Contingencies and Commitments
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 probable 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 March 31, 2021, which has not changed since December 31, 2020, 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. On November 19, 2020, FERC issued an order addressing arguments raised on rehearing of its May 21, 2020 order making minor adjustments to certain typographical errors with regard to some of the case inputs it included in its Risk Premium model analysis. However, those minor adjustments did not affect the outcome of the case, leaving the 10.02% ROE established by the May 21, 2020 order in place. Parties to these orders affecting the MISO transmission owners’ base ROE petitioned for their review at the D.C. Circuit Court of Appeals in January 2021. The NETO’s submitted an amici curia brief in support of the MISO transmission owners’ on March 17, 2021. 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.
On April 15, 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (NOPR) that proposes to eliminate the 50 basis point ROE incentive for utilities who join Regional Transmission Organizations after 3 years of membership. Comments on the NOPR are due on May 26, 2021 and reply comments are due on June 10, 2021.
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.
New York State Public Service Commission Show Cause Order Regarding Greenlight Pole Attachments
On November 20, 2020, the NYPSC issued an Order Instituting Proceeding and to Show Cause (the Show Cause Order) regarding alleged violations of the NYPSC’s 2004 Order Adopting Policy Statement on Pole Attachments, dated August 6, 2004 (the 2004 Pole Order) by RG&E, Greenlight Networks, Inc, (Greenlight), and Frontier Communications (Frontier). The alleged violations detailed in the Show Cause Order arise from Greenlight’s installation of unauthorized and substandard communications attachments throughout RG&E’s and Frontier’s service territories. The Show Cause Order directs RG&E to show cause within 30 days why the NYPSC should not pursue civil and/or administrative penalties or initiate a prudency proceeding or civil action for injunctive relief for more than 11,000 alleged violations of the 2004 Pole Order. Under NY Public Service Law Section 25-a, each alleged violation carries a potential penalty of up to $100,000 where it can be shown that the violator failed to “reasonably comply” with a statute or NYPSC order.
RG&E, Greenlight and Frontier filed respective notices to initiate settlement negotiations with respect to the alleged violations and to extend the deadline for filing a response to the Show Cause Order. The NYPSC granted the extension requests initiating settlement discussions. We cannot predict the outcome of this matter.
Beatrice Corwin Living Irrevocable Trust, by and through Its Authorized Trustee, Robert Corwin v. Iberdrola, S.A., et. al.
On January 8, 2021, the Beatrice Corwin Living Irrevocable Trust, by and through its Authorized Trustee, Robert Corwin filed a complaint in the Supreme Court of the State of New York Westchester County against Iberdrola and the members of the Company’s Board of Directors, as defendants, and the Company, as a nominal defendant with respect to certain counts contained in the complaint. The complaint alleges certain violations of fiduciary duties by Iberdrola and the members of the Company’s Board of Directors related to the existence of certain pre-emptive rights provided to Iberdrola in the Shareholder Agreement between the Company and Iberdrola, dated December 16, 2015, and the binding nature of such rights. On March 29, 2021, the parties stipulated to and requested, and the Supreme Court of the State of New York Westchester County issued an Order providing for, the transfer of the venue of the complaint to the Supreme Court, County of New York. We cannot predict the outcome of this matter.
Guarantee Commitments to Third Parties
As of March 31, 2021, we had approximately $612 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding, including $95 million related to Vineyard Wind. 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 March 31, 2021, neither we nor our subsidiaries have any liabilities recorded for these instruments.
NECEC Commitments
On January 4, 2021, CMP transferred the NECEC project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks, pursuant to the terms of a transfer agreement dated November 3, 2020. Among other things, NECEC Transmission LLC and/or CMP committed to approximately $90 million of future payments to support various programs in the state of Maine.
v3.21.1
Environmental Liabilities
 3 Months Ended
Mar. 31, 2021
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 eleven of the twenty-six sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $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 $21 million as of March 31, 2021. 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 $179 million to $291 million as of March 31, 2021. 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 March 31, 2021 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 both March 31, 2021 and December 31, 2020, the liability associated with our MGP sites in Connecticut was $96 million, 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 $301 million and $300 million as of March 31, 2021 and December 31, 2020, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2055.
FirstEnergy
NYSEG and RG&E each sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at certain former MGP sites, which are included in the discussion above. In 2011, the District Court issued a decision and order in NYSEG’s favor, which was upheld on appeal, requiring FirstEnergy to pay NYSEG for past and future clean-up costs at the sixteen sites in dispute. In 2008, the District Court issued a decision and order in RG&E favor requiring FirstEnergy to pay RG&E for past and future clean-up costs at the two MGP sites in dispute. FirstEnergy remains liable for a substantial share of clean up expenses at the MGP sites. Based on projections as of March 31, 2021, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $21 million and
$7 million, respectively. These amounts are being treated as contingent assets and have not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG and RG&E customers, as applicable.
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, and oral arguments have taken place. On May 4, 2021, the Appeals Court affirmed the court's decision striking the counts. 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 both March 31, 2021 and December 31, 2020, the amount reserved related to English Station was $22 million. 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. The parties have agreed to attempt to mediate this matter during the first half of 2021. We cannot predict the outcome of this matter.
v3.21.1
Post-retirement and Similar Obligations
 3 Months Ended
Mar. 31, 2021
Retirement Benefits [Abstract]  
Post-retirement and Similar Obligations Post-retirement and Similar ObligationsWe made $13 million of pension contributions for the three months ended March 31, 2021. We expect to make additional contributions of $61 million for the remainder of 2021.
The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,
 20212020
(Millions)  
Service cost$10 $12 
Interest cost22 27 
Expected return on plan assets(50)(50)
Amortization of:
Actuarial loss35 31 
Net Periodic Benefit Cost$17 $20 
The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2021 and 2020, respectively, consisted of: 
Three Months Ended March 31,
 20212020
(Millions)  
Service cost$1 $1 
Interest cost2 3 
Expected return on plan assets(2)(2)
Amortization of:
Prior service costs(2)(2)
Actuarial loss1 — 
Net Periodic Benefit Cost$— $— 
v3.21.1
Equity
 3 Months Ended
Mar. 31, 2021
Equity [Abstract]  
Equity Equity
As of March 31, 2021 and December 31, 2020, we had 121,188 and 413,782 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the three months ended March 31, 2021 and 2020, we released 292,594 and no shares of common stock held in trust, respectively.
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 March 2021, 53,311 shares were repurchased pursuant to the stock repurchase program. As of March 31, 2021, a total of 357,146 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 $16 million as of March 31, 2021.
Accumulated Other Comprehensive Loss 
Accumulated Other Comprehensive Loss for the three months ended March 31, 2021 and 2020, respectively, consisted of:
As of December 31,Three Months Ended March 31,As of March 31,As of December 31,Three Months Ended March 31,As of March 31,
202020212021201920202020
(Millions)      
Change in revaluation of defined benefit plans
$(12)$— $(12)$(12)$— $(12)
Loss on nonqualified pension plans(20)— (20)(7)— (7)
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(5) for 2021 and $(8) 2020
(35)(27)(62)(13)(23)(36)
Reclassification to net income of losses on cash flow hedges, net of income tax expense of $(1) for 2021 and $0 for 2020(a)
(44)1 (43)(63)2 (61)
Loss on derivatives qualifying as cash flow hedges
(79)(26)(105)(76)(21)(97)
Accumulated Other Comprehensive Loss
$(111)$(26)$(137)$(95)$(21)$(116)
(a)Reclassification is reflected in the operating expenses and interest expense, net of capitalization and line items in our condensed consolidated statements of income.
v3.21.1
Earnings Per Share
 3 Months Ended
Mar. 31, 2021
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 months ended March 31, 2021 and 2020, 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 months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,
 20212020
(Millions, except for number of shares and per share data)  
Numerator:  
Net income attributable to AVANGRID$334 $240 
Denominator:
Weighted average number of shares outstanding - basic309,495,250 309,491,082 
Weighted average number of shares outstanding - diluted309,736,266 309,623,573 
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic$1.08 $0.78 
Earnings Per Common Share, Diluted$1.08 $0.78 
v3.21.1
Segment Information
 3 Months Ended
Mar. 31, 2021
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 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 months ended March 31, 2021, consisted of:
Three Months Ended March 31, 2021NetworksRenewablesOther (a)AVANGRID Consolidated
(Millions)    
Revenue - external$1,573 $393 $— $1,966 
Depreciation and amortization156 91 — 247 
Operating income313 92 1 406 
Earnings (losses) from equity method investments2 (1)— 1 
Interest expense, net of capitalization53 — 20 73 
Income tax expense (benefit)42 (9)(19)14 
Adjusted net income229 123 2 354 
Capital expenditures531 92 — 623 
As of March 31, 2021
Property, plant and equipment17,493 9,666 9 27,168 
Equity method investments134 561 — 695 
Total assets$25,103 $11,817 $848 $37,768 
(a) Includes Corporate and intersegment eliminations.
Segment information for the three months ended March 31, 2020 and as of December 31, 2020, consisted of:
Three Months Ended March 31, 2020NetworksRenewablesOther (a)AVANGRID
Consolidated
(Millions)    
Revenue - external$1,461 $328 $— $1,789 
Depreciation and amortization148 103 — 251 
Operating income309 13 5 327 
Earnings (losses) from equity method investments2 (8)— (6)
Interest expense, net of capitalization68 1 7 76 
Income tax expense (benefit)43 (30)(1)12 
Adjusted net income198 46 (8)236 
Capital expenditures437 305 — 742 
As of December 31, 2020    
Property, plant and equipment17,079 9,662 10 26,751 
Equity method investments134 534 — 668 
Total assets$24,592 $12,867 $364 $37,823 
(a) Includes Corporate and intersegment eliminations.
Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three months ended March 31, 2021 and 2020, respectively, is as follows:
Three Months Ended March 31,
 20212020
(Millions)  
Adjusted Net Income Attributable to Avangrid, Inc.$354 $236 
Adjustments:
Mark-to-market earnings - Renewables (1)(20)18 
Restructuring charges (2)— (3)
Impact of COVID-19 (3)(6)(10)
Income tax impact of adjustments7 (2)
Net Income Attributable to Avangrid, Inc.$334 $240 
(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.
(2)Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth.
(3)Represents costs incurred in connection with the COVID-19 pandemic.
v3.21.1
Related Party Transactions
 3 Months Ended
Mar. 31, 2021
Related Party Transactions [Abstract]  
Related Party Transactions Related Party Transactions
We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations.
Related party transactions for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,20212020
(Millions)Sales ToPurchases FromSales ToPurchases From
Iberdrola Renovables Energía, S.L.$— $(2)$— $(2)
Iberdrola Financiación, S.A.$— $(2)$— $(1)
Iberdrola$— $(13)$— $(10)
Vineyard Wind$4 $— $2 $— 
Iberdrola Solutions$7 $(38)$— $— 
Other$1 $(1)$— $— 
Related party balances as of March 31, 2021 and December 31, 2020, respectively, consisted of:
As ofMarch 31, 2021December 31, 2020
(Millions)Owed ByOwed ToOwed ByOwed To
Iberdrola$2 $(11)$2 $(43)
Iberdrola Renovables Energía, S.L.$— $(2)$— $— 
Iberdrola Financiación, S.A.$— $(3)$— $(6)
Vineyard Wind$4 $— $4 $— 
Iberdrola Solutions$8 $(8)$5 $— 
Other$1 $— $1 $(1)
On December 14, 2020, AVANGRID and Iberdrola, our majority shareholder, entered into an intra-group loan agreement which provided AVANGRID with an unsecured subordinated loan in an aggregate principal amount of $3,000 million (the Iberdrola Loan).
The Iberdrola Loan bears interest (i) from December 16, 2020 until June 15, 2021, at an interest rate of 0.20%, which increases one basis point each month following the first month of the term of the Iberdrola Loan up to a maximum interest rate of 0.25%, and (ii) from June 16, 2021 until the Iberdrola Loan and any accrued and unpaid interest is repaid in its entirety, at AVANGRID’s equity cost of capital as published by Bloomberg. Interest is payable on a monthly basis in arrears.
AVANGRID is required to repay the Iberdrola Loan in full upon certain equity issuances by AVANGRID in which Iberdrola participates or a change of control of AVANGRID. In addition, on or after June 15, 2021, upon five business days’ notice to Iberdrola, AVANGRID may voluntarily repay the Iberdrola Loan and any accrued and unpaid interest, in whole or in part,
without prepayment premium or penalty if there is a change in AVANGRID’s business plan and AVANGRID determines that the Iberdrola Loan is no longer required. The intra-group loan agreement contains certain customary affirmative and negative covenants and events of default.
As of March 31, 2021 and December 31, 2020, the Iberdrola Loan had no current maturities and is included in "Non-current debt with affiliate" on our condensed consolidated balance sheets as we do not intend on repaying the Iberdrola Loan with current assets.
Other transactions with Iberdrola 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 1 for information on the Side Letter Agreement we entered into with Iberdrola.
We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable and notes receivable balances of $8 million and $5 million, respectively, as of March 31, 2021 and December 31, 2020. Renewables also has financial forward power contracts with Iberdrola Solutions to hedge Renewables' merchant wind exposure in Texas.
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 both March 31, 2021 and December 31, 2020, was zero.
AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of March 31, 2021 and December 31, 2020, there was no outstanding amount under this credit facility.
See Note 19 - Equity Method Investments for more information on Vineyard Wind, LLC (Vineyard Wind).
v3.21.1
Other Financial Statement Items
 3 Months Ended
Mar. 31, 2021
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 March 31, 2021 and December 31, 2020 consisted of:
As of March 31, 2021December 31, 2020
(Millions)
Trade receivables and unbilled revenues$1,418 $1,295 
Allowance for credit losses(135)(108)
Accounts receivable and unbilled revenues, net$1,283 $1,187 
The change in the allowance for credit losses for the three months ended March 31, 2021 and 2020 consisted of:
Three Months Ended March 31,
(Millions)20212020
As of Beginning of Period,$108 $69 
Current period provision39 19 
Write-off as uncollectible(12)(15)
As of March 31,$135 $73 
The Deferred Payment Arrangements (DPA) receivable balance was $80 million and $78 million at March 31, 2021 and December 31, 2020, respectively. The allowance for credit losses for DPAs at March 31, 2021 and December 31, 2020 was $53 million and $48 million respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three months ended March 31, 2021 and 2020, was $5 million and $0, respectively.
Prepayments and other current assets
Included in prepayments and other current assets are $145 million and $135 million of prepaid other taxes as of March 31, 2021 and December 31, 2020, respectively.
Property, plant and equipment and intangible assets
The accumulated depreciation and amortization as of March 31, 2021 and December 31, 2020, respectively, were as follows:
 March 31,December 31,
As of20212020
(Millions)  
Property, plant and equipment  
Accumulated depreciation$10,028 $9,799 
Intangible assets  
Accumulated amortization$322 $319 
Debt
As of March 31, 2021 and December 31, 2020, "Notes Payable" consisted of $0 and $309 million, respectively, of commercial paper outstanding, presented net of discounts on our condensed consolidated balance sheets.
Our $500 million credit facility was scheduled to mature on June 28, 2021. We terminated this facility on April 28, 2021.
v3.21.1
Income Tax Expense
 3 Months Ended
Mar. 31, 2021
Income Tax Disclosure [Abstract]  
Income Tax Expense Income Tax ExpenseThe effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2021, was 4.2%, which is 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 rate, inclusive of federal and state income tax, for the three months ended March 31, 2020, was 5.0%, which is 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.
v3.21.1
Stock-Based Compensation Expense
 3 Months Ended
Mar. 31, 2021
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).
Performance Stock Units
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 March 2021, 45,661 shares of common stock were issued to settle the second installment payment. The final payment will occur in 2022.
On February 15, 2021 and March 15, 2021, 1,181,031 and 75,000 PSUs, respectively, were granted to certain officers and employees of AVANGRID with achievement measured based on certain performance and market-based metrics for the 2021 to 2022 performance period. The PSUs will be payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The fair value of the PSUs on the grant date was $36.46 per share. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recently quarterly dividend payment and the stock price as of the grant date. The expense is recognized on a straight-line basis over the requisite service period of approximately four years based on expected achievement.
Restricted Stock Units
In October 2018, 8,000 RSUs were granted to an officer of AVANGRID. The RSUs vested in full in December 2020. The fair value on the grant date was determined based on a price of $47.59 per share. In March 2021, the RSU grant was settled, net of applicable taxes, by issuing 5,953 shares of common stock.
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 2021, the first installment of the RSU grant was settled by issuing 1,697 shares of common stock.
Phantom Share Units
In March 2020, 167,060 Phantom Shares were granted to certain AVANGRID executives and employees. These awards 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 March 2021, $2 million was paid to settle the second installment under this plan. As of March 31, 2021 and December 31, 2020, the total liability was $1 million and $2 million, respectively, which is included in other current liabilities.
Total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three months ended March 31, 2021 and 2020, was $4 million and $7 million, respectively.
v3.21.1
Variable Interest Entities
 3 Months Ended
Mar. 31, 2021
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 February 5, 2021, we closed on the final TEF agreement for Aeolus Wind Power VII, LLC (Aeolus VII) in a non-cash transaction. The four Aeolus VII wind farms total 688 MW of wind power.
The assets and liabilities of the VIEs totaled approximately $1,708 million and $81 million, respectively, at March 31, 2021. As of December 31, 2020, the assets and liabilities of VIEs totaled approximately $1,713 million and $107 million, respectively. At March 31, 2021 and December 31, 2020, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment.
At March 31, 2021, 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.
See Note 19 - Equity Method Investments for information on our VIE we do not consolidate.
v3.21.1
Equity Method Investments
 3 Months Ended
Mar. 31, 2021
Equity Method Investments and Joint Ventures [Abstract]  
Equity Method Investments Equity Method Investments
Renewables holds a 50% voting interest in Vineyard Wind, LLC (Vineyard Wind), a joint venture with Copenhagen Infrastructure Partners (CIP). Vineyard Wind has acquired two easements from the U.S. Bureau of Ocean Energy Management (BOEM) containing the rights to develop offshore wind generation. In total, the two lease areas have the potential to generate up to 5,000 MW of renewable energy. The first easement area is 166,886 acres located southeast of Martha's Vineyard. In 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 December 2019, DEEP selected Vineyard Wind to provide 804 MW of offshore wind through the development of its Park City Wind Project.
Vineyard Wind acquired a second offshore easement contract from BOEM. Renewables initially contributed $100 million to Vineyard Wind to acquire the easement contract, which was proportionally more than CIP's contribution. Pursuant to a joint bidding agreement between Renewables and CIP, CIP had the option to reimburse Renewables an amount, plus interest, to restore its 50% interest in the easement contract. In December 2020, CIP exercised this option and will reimburse Renewables $33 million, plus interest.
As of March 31, 2021, under the provisions of the LLC agreement, Renewables has contributed $281 million to Vineyard Wind, net of reimbursement by CIP. We expect to provide additional capital contributions.
Vineyard Wind is considered a VIE because it cannot finance its activities without additional support from its owners or third parties. Renewables is not the primary beneficiary since it does not have a controlling interest in Vineyard Wind, and therefore we do not consolidate Vineyard Wind. As of March 31, 2021 and December 31, 2020, the carrying amount of Renewables' investment in Vineyard Wind was $274 million and $245 million.
v3.21.1
Subsequent Event
 3 Months Ended
Mar. 31, 2021
Subsequent Events [Abstract]  
Subsequent Event Subsequent EventOn April 13, 2021, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on July 1, 2021 to shareholders of record at the close of business on June 4, 2021.
v3.21.1
Significant Accounting Policies and New Accounting Pronouncements (Policies)
 3 Months Ended
Mar. 31, 2021
Accounting Policies [Abstract]  
Adoption of New Accounting Pronouncements and Accounting Pronouncements Issued but Not Yet Adopted
Adoption of New Accounting Pronouncements
(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. We adopted the amendments effective January 1, 2021, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. We are applying the amendments on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment requirement.
Accounting Pronouncements Issued but Not Yet Adopted
The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2020, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.
(a) Facilitation of the effects of reference rate reform on financial reporting, and subsequent scope clarification
In March 2020, the FASB issued amendments and created ASC 848 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.
In January 2021, the FASB issued amendments to clarify the scope of ASC 848 and respond to questions from stakeholders about whether ASC 848 can be applied to derivative instruments that do not reference a rate that is expected to be discontinued but that use an interest rate for margining, discounting, or contract price alignment that is modified because of reference rate reform. The modification, commonly referred to as the “discounting transition,” may have accounting implications, raising concerns about the need to reassess previous accounting determinations related to those derivatives and about the possible hedge accounting consequences of the discounting transition. The amendments clarify that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition, capture the incremental consequences of the scope clarification and tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments are effective immediately, and may be elected retrospectively to eligible modifications as of any date from the beginning of the interim period that includes March 12, 2020, or prospectively to new modifications made on or after any date within the interim period that includes January 7, 2021.
We expect our adoption of reference rate reform and the subsequent scope clarification will not materially affect our consolidated results of operations, financial position and cash flows.
Revenue recognition
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. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. They traditionally invoice their customers by applying approved base rates to usage. 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 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. Contract assets totaled $9 million at both March 31, 2021 and December 31, 2020, 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.
v3.21.1
Revenue (Tables)
 3 Months Ended
Mar. 31, 2021
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 months ended March 31, 2021 and 2020 are as follows:
Three Months Ended March 31, 2021
 NetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity
$942 $— $— $942 
Regulated operations – natural gas
564 — — 564 
Nonregulated operations – wind
— 371 — 371 
Nonregulated operations – solar
— 4 — 4 
Nonregulated operations – thermal
— 12 — 12 
Other(a)10 32 — 42 
Revenue from contracts with customers
1,516 419 — 1,935 
Leasing revenue2 — — 2 
Derivative revenue — (31)— (31)
Alternative revenue programs
47 — — 47 
Other revenue8 5 — 13 
Total operating revenues
$1,573 $393 $— $1,966 
Three Months Ended March 31, 2020
NetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity
$873 $— $— $873 
Regulated operations – natural gas
507 — — 507 
Nonregulated operations – wind
— 211 — 211 
Nonregulated operations – solar
— 4 — 4 
Nonregulated operations – thermal
— 10 — 10 
Other(a)19 28 — 47 
Revenue from contracts with customers
1,399 253 — 1,652 
Leasing revenue1 — — 1 
Derivative revenue — 70 — 70 
Alternative revenue programs
56 — — 56 
Other revenue5 5 — 10 
Total operating revenues
$1,461 $328 $— $1,789 
(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 March 31, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:
As of March 31, 202120222023202420252026ThereafterTotal
(Millions)       
Revenue expected to be recognized on multiyear retail energy sales contracts in place
$6 $1 $1 $— $— $— $8 
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
24 16 14 12 7 68 141 
Revenue expected to be recognized on multiyear renewable energy credit sale contracts
30 18 6 3 3 2 62 
Total operating revenues$60 $35 $21 $15 $10 $70 $211 
v3.21.1
Regulatory Assets and Liabilities (Tables)
 3 Months Ended
Mar. 31, 2021
Regulated Operations [Abstract]  
Schedule of Delivery Rate Increases The below table provides a summary of
the approved 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$344.6 %$46 5.9 %$36 4.2 %
NYSEG Gas$—— %$2 0.8 %$3 1.6 %
RG&E Electric$173.8 %$14 3.2 %$16 3.3 %
RG&E Gas$—— %$— — %$2 1.3 %
Schedule of Current and Non-Current Regulatory Assets
Regulatory assets as of March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(Millions)
Pension and other post-retirement benefits cost deferrals$99 $105 
Pension and other post-retirement benefits902 927 
Storm costs460 451 
Rate adjustment mechanism 50 33 
Revenue decoupling mechanism71 58 
Transmission revenue reconciliation mechanism36 31 
Contracts for differences85 86 
Hardship programs15 20 
Plant decommissioning2 3 
Deferred purchased gas4 30 
Deferred transmission expense26 26 
Environmental remediation costs247 247 
Debt premium80 83 
Unamortized losses on reacquired debt25 26 
Unfunded future income taxes382 373 
Federal tax depreciation normalization adjustment146 148 
Asset retirement obligation21 21 
Deferred meter replacement costs36 33 
COVID-19 cost recovery11
Other212 180 
Total regulatory assets2,900 2,882 
Less: current portion317 310 
Total non-current regulatory assets$2,583 $2,572 
Schedule of Current and Non-Current Regulatory Liabilities
Regulatory liabilities as of March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(Millions)
Energy efficiency portfolio standard$51 $58 
Gas supply charge and deferred natural gas cost9 3 
Pension and other post-retirement benefits cost deferrals57 59 
Carrying costs on deferred income tax bonus depreciation32 34 
Carrying costs on deferred income tax - Mixed Services 263(a)10 11 
2017 Tax Act1,417 1,435 
Rate Change Levelization82 55 
Revenue decoupling mechanism8 9 
Accrued removal obligations1,190 1,184 
Asset sale gain account5 7 
Economic development28 28 
Positive benefit adjustment28 30 
Theoretical reserve flow thru impact9 10 
Deferred property tax29 31 
Net plant reconciliation19 20 
Debt rate reconciliation60 63 
Rate refund – FERC ROE proceeding33 33 
Transmission congestion contracts23 22 
Merger-related rate credits13 14 
Accumulated deferred investment tax credits24 25 
Asset retirement obligation18 18 
Earning sharing provisions16 17 
Middletown/Norwalk local transmission network service collections18 18 
Low income programs31 28 
Non-firm margin sharing credits17 14 
New York 2018 winter storm settlement8 9 
Other207 176 
Total regulatory liabilities3,442 3,411 
Less: current portion292 274 
Total non-current regulatory liabilities$3,150 $3,137 
v3.21.1
Fair Value of Financial Instruments and Fair Value Measurements (Tables)
 3 Months Ended
Mar. 31, 2021
Fair Value Disclosures [Abstract]  
Schedule of Fair Value Measurements
The financial instruments measured at fair value as of March 31, 2021 and December 31, 2020, respectively, consisted of:
As of March 31, 2021Level 1Level 2Level 3NettingTotal
(Millions)     
Equity investments with readily determinable fair values$43 $14 $— $— $57 
Derivative assets
Derivative financial instruments - power$7 $27 $101 $(53)$82 
Derivative financial instruments - gas— 23 17 (27)13 
Contracts for differences — — 2 — 2 
Total$7 $50 $120 $(80)$97 
Derivative liabilities
Derivative financial instruments - power$(20)$(66)$(31)$93 $(24)
Derivative financial instruments - gas(1)(5)(1)6 (1)
Contracts for differences — — (87)— (87)
Derivative financial instruments – Other— (5)— — (5)
Total$(21)$(76)$(119)$99 $(117)
As of December 31, 2020Level 1Level 2Level 3NettingTotal
(Millions)     
Equity investments with readily determinable fair values$49 $14 $— $— $63 
Derivative assets
Derivative financial instruments - power$5 $31 $105 $(54)$87 
Derivative financial instruments - gas— 24 19 (35)8 
Contracts for differences— — 2 — 2 
Total$5 $55 $126 $(89)$97 
Derivative liabilities
Derivative financial instruments - power$(23)$(31)$(23)$72 $(5)
Derivative financial instruments - gas(1)(9)(2)9 (3)
Contracts for differences— — (88)— (88)
Total$(24)$(40)$(113)$81 $(96)
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 months ended March 31, 2021 and 2020, respectively, is as follows:
Three Months Ended March 31,
(Millions)20212020
Fair Value Beginning of Period,$13 $25 
Gains recognized in operating revenues11 13 
(Losses) recognized in operating revenues(4)(10)
Total gains recognized in operating revenues7 3 
Gains recognized in OCI1 1 
(Losses) recognized in OCI(17)(5)
Total gains (losses) recognized in OCI(16)(4)
Net change recognized in regulatory assets and liabilities1 (3)
Settlements(4)(6)
Fair Value as of March 31,$1 $15 
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
$7 $3 
Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows:
Range at
Unobservable InputMarch 31, 2021
Risk of non-performance
0.39% - 0.54%
Discount rate
0.35% - 0.92%
Forward pricing ($ per KW-month)
$2.00 - $5.30
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques
The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives.
As of March 31, 2021  
IndexAvg.Max.Min.
NYMEX ($/MMBtu)$2.59 $3.47 $1.48 
AECO ($/MMBtu)$1.58 $3.24 $(0.17)
Ameren ($/MWh)$26.21 $40.53 $14.73 
COB ($/MWh)$33.68 $120.68 $8.20 
ComEd ($/MWh)$24.14 $39.26 $12.65 
ERCOT N hub ($/MWh)$32.00 $196.95 $11.25 
ERCOT S hub ($/MWh)$32.26 $203.37 $11.41 
Indiana hub ($/MWh)$28.24 $43.58 $16.36 
Mid C ($/MWh)$29.96 $95.00 $4.00 
Minn hub ($/MWh)$22.79 $37.78 $11.52 
NoIL hub ($/MWh)$24.02 $39.01 $12.70 
PJM W hub ($/MWh)$28.19 $59.53 $14.28 
v3.21.1
Derivative Instruments and Hedging (Tables)
 3 Months Ended
Mar. 31, 2021
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 March 31, 2021 and December 31, 2020, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:
As of March 31, 2021Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)    
Not designated as hedging instruments    
Derivative assets$6 $4 $6 $2 
Derivative liabilities(6)(2)(30)(78)
— 2 (24)(76)
Designated as hedging instruments
Derivative assets— — — — 
Derivative liabilities— — (4)(1)
— — (4)(1)
Total derivatives before offset of cash collateral— 2 (28)(77)
Cash collateral receivable — — 11 2 
Total derivatives as presented in the balance sheet
$— $2 $(17)$(75)
As of December 31, 2020Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)    
Not designated as hedging instruments    
Derivative assets$3 $5 $3 $3 
Derivative liabilities(3)(4)(34)(78)
— 1 (31)(75)
Designated as hedging instruments
Derivative assets— — — — 
Derivative liabilities— — (1)— 
— — (1)— 
Total derivatives before offset of cash collateral— 1 (32)(75)
Cash collateral receivable— — 18 1 
Total derivatives as presented in the balance sheet$— $1 $(14)$(74)
The tables below present Renewables' derivative positions as of March 31, 2021 and December 31, 2020, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:
As of March 31, 2021Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets$37 $82 $19 $10 
Derivative liabilities(5)(2)(39)(14)
32 80 (20)(4)
Designated as hedging instruments
Derivative assets2 1 2 14 
Derivative liabilities(6)(1)(12)(23)
(4)— (10)(9)
Total derivatives before offset of cash collateral28 80 (30)(13)
Cash collateral (payable) receivable(5)(8)16 3 
Total derivatives as presented in the balance sheet $23 $72 $(14)$(10)
As of December 31, 2020Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets$47 $89 $2 $9 
Derivative liabilities(23)(2)(4)(11)
24 87 (2)(2)
Designated as hedging instruments
Derivative assets8 15 2 7 
Derivative liabilities(5)(6)(3)(10)
3 9 (1)(3)
Total derivatives before offset of cash collateral27 96 (3)(5)
Cash collateral payable(9)(18)— — 
Total derivatives as presented in the balance sheet$18 $78 $(3)$(5)
Schedule of Notional Volumes of Outstanding Derivative Positions
The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2021 and December 31, 2020, respectively, consisted of:
 March 31,December 31,
As of20212020
(Millions)  
Wholesale electricity purchase contracts (MWh)5.2 5.6 
Natural gas purchase contracts (Dth)8.2 9.5 
Fleet fuel purchase contracts (Gallons)2.6 2.5 
The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(MWh/Dth in millions)  
Wholesale electricity purchase contracts3 3 
Wholesale electricity sales contracts7 7 
Natural gas and other fuel purchase contracts24 24 
Financial power contracts12 12 
Basis swaps – purchases32 35 
Basis swaps – sales2 2 
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 March 31, 2021 and December 31, 2020 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2021 and 2020 are as follows:
(Millions)Loss or Gain Recognized in Regulatory Assets/LiabilitiesLocation of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into IncomeLoss (Gain) Reclassified from Regulatory Assets/Liabilities into Income
As ofThree Months Ended March 31,
March 31, 2021ElectricityNatural Gas2021 ElectricityNatural Gas
Regulatory assets$13 $— Purchased power, natural gas and fuel used$2 $(1)
December 31, 20202020 
Regulatory assets$17 $1 Purchased power, natural gas and fuel used$21 $5 
The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2021 and 2020, respectively, were as follows:
Three Months Ended March 31,
 20212020
(Millions)  
Derivative assets$— $— 
Derivative liabilities$1 $(3)
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,Gain (Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2021
Interest rate contracts$— Interest expense$1 $73 
Commodity contracts1 Purchased power, natural gas and fuel used— 501 
Foreign currency exchange contracts
(4)— 
Total$(3)$1 
2020
Interest rate contracts$— Interest expense$1 $76 
Commodity contracts(2)Purchased power, natural gas and fuel used— 475 
Foreign currency exchange contracts
(6)— 
Total$(8)$1 
(a) Changes in accumulated OCI are reported on a pre-tax basis.
The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,(Loss) Gain Recognized in OCI on Derivatives (a)Location of (Gain) Reclassified from Accumulated OCI into Income(Gain) Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2021
Commodity contracts$(28)Operating revenues$(3)$1,966 
2020
Commodity contracts$7 Operating revenues$— $1,789 
(a) Changes in OCI are reported on a pre-tax basis.
The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,(Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2021
Interest rate contracts$— Interest expense$2 $73 
2020
Interest rate contracts$(31)Interest expense$1 $76 
(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 which end in 2025 and 2029.
Schedule of Fair Value, Net Derivative Contracts
The fair values of derivative contracts associated with Renewables' activities as of March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(Millions)  
Wholesale electricity purchase contracts$21 $4 
Wholesale electricity sales contracts(30)11 
Natural gas and other fuel purchase contracts13 — 
Financial power contracts67 66 
Basis swaps – purchases— 7 
Total$71 $88 
Effect of Derivatives Associated with Renewables and Gas Activities
The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2021, consisted of:
Three Months Ended March 31, 2021
TradingNon-tradingTotal amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts$7 $— 
Wholesale electricity sales contracts— (17)
Financial power contracts(5)(16)
Financial and natural gas contracts— (4)
Total gain (loss) included in operating revenues$2 $(37)$1,966 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts$— $10 
Financial power contracts— 1 
Financial and natural gas contracts— 4 
Total gain included in purchased power, natural gas and fuel used$— $15 $501 
Total Gain (Loss) $2 $(22)
The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2020, consisted of:
Three Months Ended March 31, 2020
TradingNon-tradingTotal amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts$(1)$— 
Wholesale electricity sales contracts4 11 
Financial power contracts— 22 
Total gain included in operating revenues$3 $33 $1,789 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts$— $(11)
Financial power contracts— (6)
Financial and natural gas contracts— (2)
Total loss included in purchased power, natural gas and fuel used$— $(19)$475 
Total Gain$3 $14 
v3.21.1
Post-retirement and Similar Obligations (Tables)
 3 Months Ended
Mar. 31, 2021
Retirement Benefits [Abstract]  
Components of Net Periodic Pension and Postretirement Benefits
The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,
 20212020
(Millions)  
Service cost$10 $12 
Interest cost22 27 
Expected return on plan assets(50)(50)
Amortization of:
Actuarial loss35 31 
Net Periodic Benefit Cost$17 $20 
The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2021 and 2020, respectively, consisted of: 
Three Months Ended March 31,
 20212020
(Millions)  
Service cost$1 $1 
Interest cost2 3 
Expected return on plan assets(2)(2)
Amortization of:
Prior service costs(2)(2)
Actuarial loss1 — 
Net Periodic Benefit Cost$— $— 
v3.21.1
Equity (Tables)
 3 Months Ended
Mar. 31, 2021
Equity [Abstract]  
Schedule of Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Loss for the three months ended March 31, 2021 and 2020, respectively, consisted of:
As of December 31,Three Months Ended March 31,As of March 31,As of December 31,Three Months Ended March 31,As of March 31,
202020212021201920202020
(Millions)      
Change in revaluation of defined benefit plans
$(12)$— $(12)$(12)$— $(12)
Loss on nonqualified pension plans(20)— (20)(7)— (7)
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(5) for 2021 and $(8) 2020
(35)(27)(62)(13)(23)(36)
Reclassification to net income of losses on cash flow hedges, net of income tax expense of $(1) for 2021 and $0 for 2020(a)
(44)1 (43)(63)2 (61)
Loss on derivatives qualifying as cash flow hedges
(79)(26)(105)(76)(21)(97)
Accumulated Other Comprehensive Loss
$(111)$(26)$(137)$(95)$(21)$(116)
(a)Reclassification is reflected in the operating expenses and interest expense, net of capitalization and line items in our condensed consolidated statements of income.
v3.21.1
Earnings Per Share (Tables)
 3 Months Ended
Mar. 31, 2021
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 months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,
 20212020
(Millions, except for number of shares and per share data)  
Numerator:  
Net income attributable to AVANGRID$334 $240 
Denominator:
Weighted average number of shares outstanding - basic309,495,250 309,491,082 
Weighted average number of shares outstanding - diluted309,736,266 309,623,573 
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic$1.08 $0.78 
Earnings Per Common Share, Diluted$1.08 $0.78 
v3.21.1
Segment Information (Tables)
 3 Months Ended
Mar. 31, 2021
Segment Reporting [Abstract]  
Schedule of Segment Information
Segment information as of and for the three months ended March 31, 2021, consisted of:
Three Months Ended March 31, 2021NetworksRenewablesOther (a)AVANGRID Consolidated
(Millions)    
Revenue - external$1,573 $393 $— $1,966 
Depreciation and amortization156 91 — 247 
Operating income313 92 1 406 
Earnings (losses) from equity method investments2 (1)— 1 
Interest expense, net of capitalization53 — 20 73 
Income tax expense (benefit)42 (9)(19)14 
Adjusted net income229 123 2 354 
Capital expenditures531 92 — 623 
As of March 31, 2021
Property, plant and equipment17,493 9,666 9 27,168 
Equity method investments134 561 — 695 
Total assets$25,103 $11,817 $848 $37,768 
(a) Includes Corporate and intersegment eliminations.
Segment information for the three months ended March 31, 2020 and as of December 31, 2020, consisted of:
Three Months Ended March 31, 2020NetworksRenewablesOther (a)AVANGRID
Consolidated
(Millions)    
Revenue - external$1,461 $328 $— $1,789 
Depreciation and amortization148 103 — 251 
Operating income309 13 5 327 
Earnings (losses) from equity method investments2 (8)— (6)
Interest expense, net of capitalization68 1 7 76 
Income tax expense (benefit)43 (30)(1)12 
Adjusted net income198 46 (8)236 
Capital expenditures437 305 — 742 
As of December 31, 2020    
Property, plant and equipment17,079 9,662 10 26,751 
Equity method investments134 534 — 668 
Total assets$24,592 $12,867 $364 $37,823 
(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 months ended March 31, 2021 and 2020, respectively, is as follows:
Three Months Ended March 31,
 20212020
(Millions)  
Adjusted Net Income Attributable to Avangrid, Inc.$354 $236 
Adjustments:
Mark-to-market earnings - Renewables (1)(20)18 
Restructuring charges (2)— (3)
Impact of COVID-19 (3)(6)(10)
Income tax impact of adjustments7 (2)
Net Income Attributable to Avangrid, Inc.$334 $240 
(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.
(2)Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth.
(3)Represents costs incurred in connection with the COVID-19 pandemic.
v3.21.1
Related Party Transactions (Tables)
 3 Months Ended
Mar. 31, 2021
Related Party Transactions [Abstract]  
Schedule of Related Party Transactions
Related party transactions for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,20212020
(Millions)Sales ToPurchases FromSales ToPurchases From
Iberdrola Renovables Energía, S.L.$— $(2)$— $(2)
Iberdrola Financiación, S.A.$— $(2)$— $(1)
Iberdrola$— $(13)$— $(10)
Vineyard Wind$4 $— $2 $— 
Iberdrola Solutions$7 $(38)$— $— 
Other$1 $(1)$— $— 
Related party balances as of March 31, 2021 and December 31, 2020, respectively, consisted of:
As ofMarch 31, 2021December 31, 2020
(Millions)Owed ByOwed ToOwed ByOwed To
Iberdrola$2 $(11)$2 $(43)
Iberdrola Renovables Energía, S.L.$— $(2)$— $— 
Iberdrola Financiación, S.A.$— $(3)$— $(6)
Vineyard Wind$4 $— $4 $— 
Iberdrola Solutions$8 $(8)$5 $— 
Other$1 $— $1 $(1)
v3.21.1
Other Financial Statement Items (Tables)
 3 Months Ended
Mar. 31, 2021
Balance Sheet Related Disclosures [Abstract]  
Schedule of Accounts, Notes, Loans and Financing Receivable
Accounts receivable and unbilled revenues, net as of March 31, 2021 and December 31, 2020 consisted of:
As of March 31, 2021December 31, 2020
(Millions)
Trade receivables and unbilled revenues$1,418 $1,295 
Allowance for credit losses(135)(108)
Accounts receivable and unbilled revenues, net$1,283 $1,187 
The change in the allowance for credit losses for the three months ended March 31, 2021 and 2020 consisted of:
Three Months Ended March 31,
(Millions)20212020
As of Beginning of Period,$108 $69 
Current period provision39 19 
Write-off as uncollectible(12)(15)
As of March 31,$135 $73 
Schedule of Accumulated Depreciation and Amortization
The accumulated depreciation and amortization as of March 31, 2021 and December 31, 2020, respectively, were as follows:
 March 31,December 31,
As of20212020
(Millions)  
Property, plant and equipment  
Accumulated depreciation$10,028 $9,799 
Intangible assets  
Accumulated amortization$322 $319 
v3.21.1
Background and Nature Of Operations (Details) - USD ($)
Apr. 15, 2021
Oct. 20, 2020
Mar. 31, 2021
NM Green Holdings, Inc.      
Nature Of Business [Line Items]      
Merger agreement, share price (in dollars per share)   $ 50.30  
Merger agreement term, ownership percentage benchmark (no more than)   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  
NM Green Holdings, Inc. | Side Letter Agreement Associated With Merger | Subsequent Event      
Nature Of Business [Line Items]      
Debt basis spread on variable rate 0.75%    
Facility fee percentage on undrawn portion of funding commitment 0.12%    
Avangrid | Iberdrola S.A.      
Nature Of Business [Line Items]      
Parent company, ownership percentage     81.50%
v3.21.1
Revenue - Narrative (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Dec. 31, 2020
Disaggregation of Revenue [Line Items]      
Contract assets $ 9   $ 9
TCC contract liabilities 5   9
Revenue recognized 4 $ 5  
Accounts receivable related to contracts with customers 1,222   1,151
Unbilled revenues 292   $ 341
Revenue, remaining performance obligation, amount $ 211    
Transmission congestion contracts | Min.      
Disaggregation of Revenue [Line Items]      
Revenue performance obligation, timing 6 months    
Transmission congestion contracts | Max.      
Disaggregation of Revenue [Line Items]      
Revenue performance obligation, timing 2 years    
Renewables      
Disaggregation of Revenue [Line Items]      
Capitalized contract cost amortization term 15 years    
v3.21.1
Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Segment Reporting Information [Line Items]    
Revenue from contracts with customers $ 1,935 $ 1,652
Leasing revenue 2 1
Derivative revenue (31) 70
Alternative revenue programs 47 56
Other revenue 13 10
Total operating revenues 1,966 1,789
Regulated operations – electricity    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 942 873
Regulated operations – natural gas    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 564 507
Nonregulated operations – wind    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 371 211
Nonregulated operations – solar    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 4 4
Nonregulated operations – thermal    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 12 10
Other    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 42 47
Other    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Leasing revenue 0 0
Derivative revenue 0 0
Alternative revenue programs 0 0
Other revenue 0 0
Total operating revenues 0 0
Other | Regulated operations – electricity    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Other | Regulated operations – natural gas    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Other | Nonregulated operations – wind    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Other | Nonregulated operations – solar    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Other | Nonregulated operations – thermal    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Other | Other    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Networks    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 1,516 1,399
Leasing revenue 2 1
Derivative revenue 0 0
Alternative revenue programs 47 56
Other revenue 8 5
Total operating revenues 1,573 1,461
Networks | Regulated operations – electricity    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 942 873
Networks | Regulated operations – natural gas    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 564 507
Networks | Nonregulated operations – wind    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Networks | Nonregulated operations – solar    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Networks | Nonregulated operations – thermal    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Networks | Other    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 10 19
Renewables    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 419 253
Leasing revenue 0 0
Derivative revenue (31) 70
Alternative revenue programs 0 0
Other revenue 5 5
Total operating revenues 393 328
Renewables | Regulated operations – electricity    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Renewables | Regulated operations – natural gas    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 0 0
Renewables | Nonregulated operations – wind    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 371 211
Renewables | Nonregulated operations – solar    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 4 4
Renewables | Nonregulated operations – thermal    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers 12 10
Renewables | Other    
Segment Reporting Information [Line Items]    
Revenue from contracts with customers $ 32 $ 28
v3.21.1
Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details)
$ in Millions
Mar. 31, 2021
USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 211
Revenue expected to be recognized on multiyear retail energy sales contracts in place  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues 8
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues 141
Revenue expected to be recognized on multiyear renewable energy credit sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues 62
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-04-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 69
Remaining performance obligation, period 9 months
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 $ 60
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 6
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 24
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 30
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 35
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 1
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 16
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 18
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 21
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 1
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 14
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 6
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 15
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 0
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 12
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 3
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 10
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 0
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 7
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 3
Remaining performance obligation, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 70
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 0
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 68
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total operating revenues $ 2
Remaining performance obligation, period
v3.21.1
Regulatory Assets and Liabilities - Additional Information (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Apr. 14, 2021
Nov. 19, 2020
Feb. 19, 2020
Jan. 01, 2019
Jan. 01, 2018
Jan. 01, 2017
Mar. 31, 2021
Mar. 31, 2020
Dec. 31, 2020
Dec. 31, 2019
Regulatory Assets And Liabilities [Line Items]                    
Unrecorded regulatory assets             $ 1,473      
Unfunded future income tax expense collection period             46 years      
UIL Holdings                    
Regulatory Assets And Liabilities [Line Items]                    
Business combination merger related rate credits             $ 1 $ 1    
Energy efficiency portfolio standard                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 3 years  
Carrying costs on deferred income tax bonus depreciation                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 3 years  
Rate Change Levelization                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 5 years  
Positive benefit adjustment                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 3 years  
Theoretical reserve flow thru impact | Max.                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 5 years  
Theoretical reserve flow thru impact | Min.                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 3 years  
Deferred property tax                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 5 years  
Net plant reconciliation                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 5 years  
Transmission congestion contracts                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 5 years  
New York 2018 winter storm settlement                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 3 years  
Carrying costs on deferred income tax - Mixed Services 263(a)                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 3 years  
Central Maine Power                    
Regulatory Assets And Liabilities [Line Items]                    
Distribution revenue requirement     $ 17              
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      
NYSEG and RG&E                    
Regulatory Assets And Liabilities [Line Items]                    
Return on equity   8.80%                
Equity ratio for earnings sharing   48.00%                
Equity ratio   50.00%                
NYSEG and RG&E | Economic development                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 3 years  
United Illuminating Company (UI) | Subsequent Event                    
Regulatory Assets And Liabilities [Line Items]                    
Under-recoveries, amortization period 5 years 8 months                  
United Illuminating Company (UI) | PURA                    
Regulatory Assets And Liabilities [Line Items]                    
Return on equity           9.10%        
Equity ratio           50.00%        
New distribution rate schedule, period           3 years        
Public utilities regulatory authority distribution rate           50.00%        
SCG | PURA                    
Regulatory Assets And Liabilities [Line Items]                    
Return on equity         9.25%          
Equity ratio         52.00%          
Connecticut Natural Gas Corporation (CNG) | PURA                    
Regulatory Assets And Liabilities [Line Items]                    
Return on equity       9.30%            
Equity ratio, year one       54.00%            
Equity ratio, year two       54.50%            
Equity ratio, year three       55.00%            
BGC | Massachusetts Department of Public Utilities (DPU)                    
Regulatory Assets And Liabilities [Line Items]                    
Equity ratio                   54.00%
Public utilities regulatory authority distribution rate                   9.70%
NYSEG | Asset sale gain account                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 3 years  
RG&E | Asset sale gain account                    
Regulatory Assets And Liabilities [Line Items]                    
Regulatory liability, amortization period                 2 years  
v3.21.1
Regulatory Assets and Liabilities - Rate Increases and Delivery Rate Percentages (Details)
$ in Millions
Jun. 22, 2020
USD ($)
NYSEG Electric | Electric and Gas Service Rate Plan Year One  
Regulatory Liabilities [Line Items]  
Rate Increase $ 34
Delivery Rate Increase 4.60%
NYSEG Electric | Electric and Gas Service Rate Plan Year Two  
Regulatory Liabilities [Line Items]  
Rate Increase $ 46
Delivery Rate Increase 5.90%
NYSEG Electric | Electric and Gas Service Rate Plan Year Three  
Regulatory Liabilities [Line Items]  
Rate Increase $ 36
Delivery Rate Increase 4.20%
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 $ 2
Delivery Rate Increase 0.80%
NYSEG Gas | Electric and Gas Service Rate Plan Year Three  
Regulatory Liabilities [Line Items]  
Rate Increase $ 3
Delivery Rate Increase 1.60%
RG&E Electric | Electric and Gas Service Rate Plan Year One  
Regulatory Liabilities [Line Items]  
Rate Increase $ 17
Delivery Rate Increase 3.80%
RG&E Electric | Electric and Gas Service Rate Plan Year Two  
Regulatory Liabilities [Line Items]  
Rate Increase $ 14
Delivery Rate Increase 3.20%
RG&E Electric | Electric and Gas Service Rate Plan Year Three  
Regulatory Liabilities [Line Items]  
Rate Increase $ 16
Delivery Rate Increase 3.30%
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
Delivery Rate Increase 1.30%
v3.21.1
Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($)
$ in Millions
Mar. 31, 2021
Dec. 31, 2020
Regulatory Assets [Line Items]    
Total regulatory assets $ 2,900 $ 2,882
Less: current portion 317 310
Total non-current regulatory assets 2,583 2,572
Pension and other post-retirement benefits cost deferrals    
Regulatory Assets [Line Items]    
Total regulatory assets 99 105
Pension and other post-retirement benefits    
Regulatory Assets [Line Items]    
Total regulatory assets 902 927
Storm costs    
Regulatory Assets [Line Items]    
Total regulatory assets 460 451
Rate adjustment mechanism    
Regulatory Assets [Line Items]    
Total regulatory assets 50 33
Revenue decoupling mechanism    
Regulatory Assets [Line Items]    
Total regulatory assets 71 58
Transmission revenue reconciliation mechanism    
Regulatory Assets [Line Items]    
Total regulatory assets 36 31
Contracts for differences    
Regulatory Assets [Line Items]    
Total regulatory assets 85 86
Hardship programs    
Regulatory Assets [Line Items]    
Total regulatory assets 15 20
Plant decommissioning    
Regulatory Assets [Line Items]    
Total regulatory assets 2 3
Deferred purchased gas    
Regulatory Assets [Line Items]    
Total regulatory assets 4 30
Deferred transmission expense    
Regulatory Assets [Line Items]    
Total regulatory assets 26 26
Environmental remediation costs    
Regulatory Assets [Line Items]    
Total regulatory assets 247 247
Debt premium    
Regulatory Assets [Line Items]    
Total regulatory assets 80 83
Unamortized losses on reacquired debt    
Regulatory Assets [Line Items]    
Total regulatory assets 25 26
Unfunded future income taxes    
Regulatory Assets [Line Items]    
Total regulatory assets 382 373
Federal tax depreciation normalization adjustment    
Regulatory Assets [Line Items]    
Total regulatory assets 146 148
Asset retirement obligation    
Regulatory Assets [Line Items]    
Total regulatory assets 21 21
Deferred meter replacement costs    
Regulatory Assets [Line Items]    
Total regulatory assets 36 33
COVID-19 cost recovery    
Regulatory Assets [Line Items]    
Total regulatory assets 1 1
Other    
Regulatory Assets [Line Items]    
Total regulatory assets $ 212 $ 180
v3.21.1
Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($)
$ in Millions
Mar. 31, 2021
Dec. 31, 2020
Regulatory Liabilities [Line Items]    
Total regulatory liabilities $ 3,442 $ 3,411
Less: current portion 292 274
Total non-current regulatory liabilities 3,150 3,137
Energy efficiency portfolio standard    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 51 58
Gas supply charge and deferred natural gas cost    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 9 3
Pension and other post-retirement benefits cost deferrals    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 57 59
Carrying costs on deferred income tax bonus depreciation    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 32 34
Carrying costs on deferred income tax - Mixed Services 263(a)    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 10 11
2017 Tax Act    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 1,417 1,435
Rate Change Levelization    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 82 55
Revenue decoupling mechanism    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 8 9
Accrued removal obligations    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 1,190 1,184
Asset sale gain account    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 5 7
Economic development    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 28 28
Positive benefit adjustment    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 28 30
Theoretical reserve flow thru impact    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 9 10
Deferred property tax    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 29 31
Net plant reconciliation    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 19 20
Debt rate reconciliation    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 60 63
Rate refund – FERC ROE proceeding    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 33 33
Transmission congestion contracts    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 23 22
Merger-related rate credits    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 13 14
Accumulated deferred investment tax credits    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 24 25
Asset retirement obligation    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 18 18
Earning sharing provisions    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 16 17
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 31 28
Non-firm margin sharing credits    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 17 14
New York 2018 winter storm settlement    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities 8 9
Other    
Regulatory Liabilities [Line Items]    
Total regulatory liabilities $ 207 $ 176
v3.21.1
Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative delivery period (in years) 2 years  
Restricted cash $ 350 $ 331
Fair value of debt 11,607 12,166
Restricted Cash    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Restricted cash $ 4 $ 4
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%  
v3.21.1
Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($)
$ in Millions
Mar. 31, 2021
Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Equity investments with readily determinable fair values $ 57 $ 63
Netting adjustment (80) (89)
Derivative assets 97 97
Netting adjustment 99 81
Derivative liabilities (117) (96)
Derivative financial instruments - power    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Netting adjustment (53) (54)
Derivative assets 82 87
Netting adjustment 93 72
Derivative liabilities (24) (5)
Derivative financial instruments - gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Netting adjustment (27) (35)
Derivative assets 13 8
Netting adjustment 6 9
Derivative liabilities (1) (3)
Contracts for differences    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Netting adjustment 0 0
Derivative assets 2 2
Netting adjustment 0 0
Derivative liabilities (87) (88)
Derivative financial instruments – Other    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Netting adjustment 0  
Derivative liabilities (5)  
Level 1    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Equity investments with readily determinable fair values 43 49
Derivative assets, before netting 7 5
Derivative liabilities, before netting (21) (24)
Level 1 | Derivative financial instruments - power    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets, before netting 7 5
Derivative liabilities, before netting (20) (23)
Level 1 | Derivative financial instruments - gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets, before netting 0 0
Derivative liabilities, before netting (1) (1)
Level 1 | Contracts for differences    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets, before netting 0 0
Derivative liabilities, before netting 0 0
Level 1 | Derivative financial instruments – Other    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative liabilities, before netting 0  
Level 2    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Equity investments with readily determinable fair values 14 14
Derivative assets, before netting 50 55
Derivative liabilities, before netting (76) (40)
Level 2 | Derivative financial instruments - power    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets, before netting 27 31
Derivative liabilities, before netting (66) (31)
Level 2 | Derivative financial instruments - gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets, before netting 23 24
Derivative liabilities, before netting (5) (9)
Level 2 | Contracts for differences    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets, before netting 0 0
Derivative liabilities, before netting 0 0
Level 2 | Derivative financial instruments – Other    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative liabilities, before netting (5)  
Level 3    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Equity investments with readily determinable fair values 0 0
Derivative assets, before netting 120 126
Derivative liabilities, before netting (119) (113)
Level 3 | Derivative financial instruments - power    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets, before netting 101 105
Derivative liabilities, before netting (31) (23)
Level 3 | Derivative financial instruments - gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets, before netting 17 19
Derivative liabilities, before netting (1) (2)
Level 3 | Contracts for differences    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets, before netting 2 2
Derivative liabilities, before netting (87) $ (88)
Level 3 | Derivative financial instruments – Other    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative liabilities, before netting $ 0  
v3.21.1
Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]    
Fair Value Beginning of Period, $ 13 $ 25
Gains recognized in operating revenues 11 13
(Losses) recognized in operating revenues (4) (10)
Total gains recognized in operating revenues 7 3
Gains recognized in OCI 1 1
(Losses) recognized in OCI (17) (5)
Total gains (losses) recognized in OCI (16) (4)
Net change recognized in regulatory assets and liabilities 1 (3)
Settlements (4) (6)
Fair Value as of March 31, 1 15
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 $ 7 $ 3
v3.21.1
Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Details) - Measurement Input, Commodity Forward Price
Mar. 31, 2021
$ / MWh
$ / MMBTU
CME SWAPS MARKETS (NYMEX) | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input | $ / MMBTU 2.59
CME SWAPS MARKETS (NYMEX) | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input | $ / MMBTU 3.47
CME SWAPS MARKETS (NYMEX) | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input | $ / MMBTU 1.48
AECO | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input | $ / MMBTU 1.58
AECO | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input | $ / MMBTU 3.24
AECO | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input | $ / MMBTU (0.17)
Ameren | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 26.21
Ameren | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 40.53
Ameren | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 14.73
COB | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 33.68
COB | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 120.68
COB | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 8.20
ComEd | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 24.14
ComEd | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 39.26
ComEd | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 12.65
ERCOT N hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 32.00
ERCOT N hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 196.95
ERCOT N hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 11.25
ERCOT S Hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 32.26
ERCOT S Hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 203.37
ERCOT S Hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 11.41
Indiana Hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 28.24
Indiana Hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 43.58
Indiana Hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 16.36
Mid C | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 29.96
Mid C | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 95.00
Mid C | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 4.00
Minn Hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 22.79
Minn Hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 37.78
Minn Hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 11.52
Noil Hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 24.02
Noil Hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 39.01
Noil Hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 12.70
PJM W hub | Avg.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 28.19
PJM W hub | Max.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 59.53
PJM W hub | Min.  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 14.28
v3.21.1
Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Details) - Level 3 - Contracts for differences
Mar. 31, 2021
$ / 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 0.0039
Min. | Discount rate  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 0.0035
Min. | Measurement Input, Commodity Forward Price  
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 0.0054
Max. | Discount rate  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 0.0092
Max. | Measurement Input, Commodity Forward Price  
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]  
Derivative measurement input 5.30
v3.21.1
Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Details) - USD ($)
$ in Millions
Mar. 31, 2021
Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative Asset $ 97 $ 97
Derivative liabilities (117) (96)
Cash collateral (payable) receivable, Asset (24) (18)
Networks | Current Assets    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Asset 0 0
Cash collateral (payable) receivable, Asset 0 0
Total derivatives as presented in the balance sheet, Asset 0 0
Networks | Current Assets | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 6 3
Derivative liabilities (6) (3)
Derivative Asset 0 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 1
Cash collateral (payable) receivable, Asset 0 0
Total derivatives as presented in the balance sheet, Asset 2 1
Networks | Noncurrent Assets | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 4 5
Derivative liabilities (2) (4)
Derivative Asset 2 1
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 (28) (32)
Cash collateral (payable) receivable, Liability 11 18
Total derivatives as presented in the balance sheet, Liability (17) (14)
Networks | Current Liabilities | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 6 3
Derivative liabilities (30) (34)
Derivative liabilities (24) (31)
Networks | Current Liabilities | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 0 0
Derivative liabilities (4) (1)
Derivative liabilities (4) (1)
Networks | Noncurrent Liabilities    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Liability (77) (75)
Cash collateral (payable) receivable, Liability 2 1
Total derivatives as presented in the balance sheet, Liability (75) (74)
Networks | Noncurrent Liabilities | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 2 3
Derivative liabilities (78) (78)
Derivative liabilities (76) (75)
Networks | Noncurrent Liabilities | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 0 0
Derivative liabilities (1) 0
Derivative liabilities (1) 0
Renewables | Current Assets    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Asset 28 27
Cash collateral (payable) receivable, Asset (5) (9)
Total derivatives as presented in the balance sheet, Asset 23 18
Renewables | Current Assets | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 37 47
Derivative liabilities (5) (23)
Derivative Asset 32 24
Renewables | Current Assets | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 2 8
Derivative liabilities (6) (5)
Derivative Asset (4) 3
Renewables | Noncurrent Assets    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Asset 80 96
Cash collateral (payable) receivable, Asset (8) (18)
Total derivatives as presented in the balance sheet, Asset 72 78
Renewables | Noncurrent Assets | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 82 89
Derivative liabilities (2) (2)
Derivative Asset 80 87
Renewables | Noncurrent Assets | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 1 15
Derivative liabilities (1) (6)
Derivative Asset 0 9
Renewables | Current Liabilities    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Liability (30) (3)
Cash collateral (payable) receivable, Liability 16 0
Total derivatives as presented in the balance sheet, Liability (14) (3)
Renewables | Current Liabilities | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 19 2
Derivative liabilities (39) (4)
Derivative liabilities (20) (2)
Renewables | Current Liabilities | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 2 2
Derivative liabilities (12) (3)
Derivative liabilities (10) (1)
Renewables | Noncurrent Liabilities    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Total derivatives before offset of cash collateral, Liability (13) (5)
Cash collateral (payable) receivable, Liability 3 0
Total derivatives as presented in the balance sheet, Liability (10) (5)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 10 9
Derivative liabilities (14) (11)
Derivative liabilities (4) (2)
Renewables | Noncurrent Liabilities | Designated as hedging instruments    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets 14 7
Derivative liabilities (23) (10)
Derivative liabilities $ (9) $ (3)
v3.21.1
Derivative Instruments and Hedging - Net Notional Volume (Details)
gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions
 3 Months Ended 12 Months Ended
Mar. 31, 2021
USD ($)
MWh
MMBTU
gal
Dec. 31, 2020
USD ($)
MMBTU
MWh
gal
Networks | Wholesale Electricity Contract | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount, energy measure | MWh 5.2 5.6
Networks | Natural Gas Contracts | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount, energy measure | MMBTU 8.2 9.5
Networks | Fleet Fuel Contracts | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount | gal 2.6 2.5
Renewables    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets (liabilities), fair value $ 71 $ 88
Renewables | Wholesale Electricity Contract | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount, energy measure | MWh 3.0 3.0
Derivative assets (liabilities), fair value $ 21 $ 4
Renewables | Wholesale Electricity Contract | Short    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount, energy measure | MWh 7.0 7.0
Derivative assets (liabilities), fair value $ (30) $ 11
Renewables | Natural Gas and Other fuel Contracts | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount, energy measure | MMBTU 24.0 24.0
Derivative assets (liabilities), fair value $ 13 $ 0
Renewables | Financial Power Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount, energy measure | MMBTU 12.0 12.0
Derivative assets (liabilities), fair value $ 67 $ 66
Renewables | Basis swaps    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets (liabilities), fair value $ 0 $ 7
Renewables | Basis swaps | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount, energy measure | MMBTU 32.0 35.0
Renewables | Basis swaps | Short    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, nonmonetary notional amount, energy measure | MMBTU 2.0 2.0
v3.21.1
Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Dec. 31, 2020
Derivative Assets      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income $ 0 $ 0  
Derivative Liabilities      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income 1 (3)  
Electricity | Regulatory Assets      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Loss or Gain Recognized in Regulatory Assets/Liabilities 13   $ 17
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income 2 21  
Natural Gas | Regulatory Assets      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Loss or Gain Recognized in Regulatory Assets/Liabilities 0   $ 1
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income $ (1) $ 5  
v3.21.1
Derivative Instruments and Hedging - Additional Information (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2021
USD ($)
instrument
Mar. 31, 2020
USD ($)
Dec. 31, 2020
USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Regulatory assets $ 2,900   $ 2,882
Regulatory liabilities 3,442   3,411
Aggregate fair value of additional collateral 16    
Cash collateral pledged 24   18
Collateral already posted $ 13    
Contracts for differences      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Number of derivative instruments | instrument 2    
Interest Rate Contract      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Gain (loss) recognized in OCI on derivatives $ 0 $ (31)  
Previously Settled Interest Rate Contracts      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Gain (loss) recognized in OCI on derivatives (2) (1)  
Cash Flow Hedging | Interest Rate Contract      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Expected amortization of discontinued cash flow hedges in 2021 7    
Cash Flow Hedging | Previously Settled Interest Rate Contracts      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Net loss related to previously settled forward starting swaps 55   57
Networks      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Gain (loss) recognized in OCI on derivatives (3) (8)  
Networks | Cash Flow Hedging      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Gain (loss) recognized in OCI on derivatives (1) $ (1)  
Expected amortization of discontinued cash flow hedges in 2021 3    
Unrealized losses on hedge derivatives reported in OCI 4    
Unrealized gains (losses) on hedge derivatives to be reclassified within next 12 months 0    
Networks | Cash Flow Hedging | Previously Settled Forward Starting Swaps      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Net loss related to previously settled forward starting swaps $ 50   51
Networks | Cash Flow Hedging | Fuel Derivatives      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Maximum period of time of cash flow hedges 12 months    
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 $ (13)    
UI | Contracts for differences      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Percentage of cost or benefit on contract allocated to customers 20.00%    
Gross derivative asset $ 2   2
Regulatory assets 85   86
Gross amounts of recognized liabilities 87   88
Regulatory liabilities $ 0   0
CL&P | Contracts for differences      
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
Gross amounts of recognized liabilities $ 84   $ 85
v3.21.1
Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Interest Expense $ 73 $ 76
Purchased power, natural gas and fuel used 501 475
Revenues 1,966 1,789
Networks    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
(Loss) Gain Recognized in OCI on Derivatives (3) (8)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax 1 1
Revenues 1,573 1,461
Renewables    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Revenues 393 328
Interest Rate Contract    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
(Loss) Gain Recognized in OCI on Derivatives 0 (31)
Interest Rate Contract | Interest Expense    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax 2 1
Interest Rate Contract | Networks | Interest Expense    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
(Loss) Gain Recognized in OCI on Derivatives 0 0
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax 1 1
Commodity Contract | Networks | Operating Expense    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
(Loss) Gain Recognized in OCI on Derivatives 1 (2)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax 0 0
Commodity Contract | Renewables    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
(Loss) Gain Recognized in OCI on Derivatives (28) 7
Commodity Contract | Renewables | Operating revenues    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax (3) 0
Foreign Exchange Contract | Networks | Operating Expense    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
(Loss) Gain Recognized in OCI on Derivatives (4) (6)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax $ 0 $ 0
v3.21.1
Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($)
$ in Millions
Mar. 31, 2021
Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets (liabilities), fair value $ 71 $ 88
Financial Power Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets (liabilities), fair value 67 66
Basis swaps    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets (liabilities), fair value 0 7
Long | Wholesale Electricity Contract    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets (liabilities), fair value 21 4
Long | Natural Gas and Other fuel Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets (liabilities), fair value 13 0
Short | Wholesale Electricity Contract    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative assets (liabilities), fair value $ (30) $ 11
v3.21.1
Derivative Instruments and Hedging - Effect of Trading and Non-trading Derivatives (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Revenues $ 1,966 $ 1,789
Utilities operating expense, purchased power 501 475
Renewables    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Revenues 393 328
Renewables | Trading    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 2 3
Renewables | Non-trading    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net (22) 14
Renewables | Operating revenues | Trading    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 2 3
Renewables | Operating revenues | Trading | Wholesale Electricity Contract | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 7 (1)
Renewables | Operating revenues | Trading | Wholesale Electricity Contract | Short    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 0 4
Renewables | Operating revenues | Trading | Financial Power Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net (5) 0
Renewables | Operating revenues | Trading | Financial and Natural Gas Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 0  
Renewables | Operating revenues | Non-trading    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net (37) 33
Revenues 1,966 1,789
Renewables | Operating revenues | Non-trading | Wholesale Electricity Contract | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 0 0
Renewables | Operating revenues | Non-trading | Wholesale Electricity Contract | Short    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net (17) 11
Renewables | Operating revenues | Non-trading | Financial Power Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net (16) 22
Renewables | Operating revenues | Non-trading | Financial and Natural Gas Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net (4)  
Renewables | Operating Expense | Trading    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 0 0
Renewables | Operating Expense | Trading | Wholesale Electricity Contract | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 0 0
Renewables | Operating Expense | Trading | Financial Power Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 0 0
Renewables | Operating Expense | Trading | Financial and Natural Gas Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 0 0
Renewables | Operating Expense | Non-trading    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 15 (19)
Utilities operating expense, purchased power 501 475
Renewables | Operating Expense | Non-trading | Wholesale Electricity Contract | Long    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 10 (11)
Renewables | Operating Expense | Non-trading | Financial Power Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net 1 (6)
Renewables | Operating Expense | Non-trading | Financial and Natural Gas Contracts    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative, gain (loss) on derivative, net $ 4 $ (2)
v3.21.1
Contingencies (Details)
violation in Thousands, $ in Millions
 1 Months Ended 3 Months Ended 12 Months Ended
Nov. 20, 2020
violation
May 21, 2020
May 20, 2020
Nov. 21, 2019
complaint
Jan. 11, 2019
complaint
Mar. 22, 2016
Mar. 03, 2015
Oct. 16, 2014
Sep. 30, 2011
Apr. 30, 2018
Mar. 31, 2021
USD ($)
Dec. 31, 2001
plaintiff
Jan. 04, 2021
USD ($)
Dec. 31, 2020
USD ($)
Apr. 12, 2016
USD ($)
Loss Contingencies [Line Items]                              
Refund period term                 15 months            
Approved return on equity       9.88%                      
Regulatory liabilities                     $ 3,150     $ 3,137  
Number of claims | complaint       2                      
Requested existing base return on equity base percentage   10.02% 9.88%                        
Number of plaintiffs | plaintiff                       2      
Show cause order, period 30 days                            
Show cause order, number of alleged violations with civil action for injunctive relief | violation 11                            
Standby letters of credit, surety bonds, guarantees and indemnifications outstanding                     612        
Future payments committed                         $ 90    
Vineyard Wind                              
Loss Contingencies [Line Items]                              
Standby letters of credit, surety bonds, guarantees and indemnifications outstanding                     95        
Complaint II                              
Loss Contingencies [Line Items]                              
Regulatory liabilities                     26        
Complaint III                              
Loss Contingencies [Line Items]                              
Regulatory liabilities                     7        
Complaint II and III                              
Loss Contingencies [Line Items]                              
Reasonably possible loss, in additional reserve, pre tax                     $ 17        
California Energy Crisis Litigation                              
Loss Contingencies [Line Items]                              
Price of the power purchase agreements                             $ 259
Requested renewables delay from preliminary proposed ruling period                   2 years          
Unfavorable Regulatory Action | Complaint I                              
Loss Contingencies [Line Items]                              
Approved return on equity               10.57%              
Number of claims | complaint         4                    
Unfavorable Regulatory Action | Complaint I | Max.                              
Loss Contingencies [Line Items]                              
Approved return on equity             11.74% 11.74%              
Unfavorable Regulatory Action | Complaint II                              
Loss Contingencies [Line Items]                              
Approved return on equity           9.59%                  
Refund period           15 months                  
Unfavorable Regulatory Action | Complaint II | Max.                              
Loss Contingencies [Line Items]                              
Approved return on equity           10.42%                  
Unfavorable Regulatory Action | Complaint III                              
Loss Contingencies [Line Items]                              
Approved return on equity           10.90%                  
Refund period           15 months                  
Unfavorable Regulatory Action | Complaint III | Max.                              
Loss Contingencies [Line Items]                              
Approved return on equity           12.19%                  
Before Amendment                              
Loss Contingencies [Line Items]                              
Requested return on equity base percentage                 11.14%            
v3.21.1
Environmental Liabilities (Details)
 3 Months Ended 12 Months Ended
Apr. 24, 2020
USD ($)
Mar. 31, 2021
USD ($)
site
Dec. 31, 2008
site
Dec. 31, 2020
USD ($)
Aug. 04, 2016
USD ($)
Environmental Exit Cost [Line Items]          
Number of sites with potential remediation obligations   26      
Number of sites with liability recorded   11      
Number of sits note expected to incur additional liabilities   15      
Number of additional sites with liability recorded   12      
Number of sites where gas was manufactured in the past   53      
Number of sites for which we have entered into consent orders to investigate and remediate   41      
Accrual related to investigation and remediation | $   $ 301,000,000   $ 300,000,000  
Loss contingency, damages sought, value | $ $ 5,000,000        
FirstEnergy          
Environmental Exit Cost [Line Items]          
Number of sites in dispute     16    
United Illuminating Company (UI)          
Environmental Exit Cost [Line Items]          
Accrual related to investigation and remediation | $   $ 22,000,000   22,000,000 $ 30,000,000
New York State Registry          
Environmental Exit Cost [Line Items]          
Number of sites with potential remediation obligations   16      
Number of sites where gas was manufactured in the past   6      
Maine's Uncontrolled Sites Program          
Environmental Exit Cost [Line Items]          
Number of sites with potential remediation obligations   5      
Number of sites where gas was manufactured in the past   2      
Brownfield Cleanup Program          
Environmental Exit Cost [Line Items]          
Number of sites with potential remediation obligations   1      
Massachusetts Non- Priority Confirmed Disposal Site List          
Environmental Exit Cost [Line Items]          
Number of sites with potential remediation obligations   1      
National Priorities List          
Environmental Exit Cost [Line Items]          
Number of sites with potential remediation obligations   6      
Ten of Twenty-five Sites          
Environmental Exit Cost [Line Items]          
Estimated environmental liability | $   $ 6,000,000      
Another Ten Sites          
Environmental Exit Cost [Line Items]          
Estimated environmental liability | $   9,000,000      
Another Ten Sites | Min.          
Environmental Exit Cost [Line Items]          
Estimated environmental liability | $   13,000,000      
Another Ten Sites | Max.          
Environmental Exit Cost [Line Items]          
Estimated environmental liability | $   $ 21,000,000      
New York Voluntary Cleanup Program          
Environmental Exit Cost [Line Items]          
Number of sites where gas was manufactured in the past   3      
Maine's Voluntary Response Action Program          
Environmental Exit Cost [Line Items]          
Number of sites where gas was manufactured in the past   3      
Manufactured Gas Plants | Connecticut          
Environmental Exit Cost [Line Items]          
Accrual related to investigation and remediation | $   $ 96,000,000   $ 96,000,000  
Manufactured Gas Plants | Min.          
Environmental Exit Cost [Line Items]          
Accrual related to investigation and remediation | $   179,000,000      
Manufactured Gas Plants | Max.          
Environmental Exit Cost [Line Items]          
Accrual related to investigation and remediation | $   291,000,000      
Properties Where MGPs Had Historically Operated          
Environmental Exit Cost [Line Items]          
Accrual related to investigation and remediation | $   0      
NYSEG | FirstEnergy          
Environmental Exit Cost [Line Items]          
Accrual related to investigation and remediation | $   21,000,000      
RG&E | FirstEnergy          
Environmental Exit Cost [Line Items]          
Accrual related to investigation and remediation | $   $ 7,000,000      
MGP Sites | FirstEnergy          
Environmental Exit Cost [Line Items]          
Number of sites in dispute     2    
v3.21.1
Post-Retirement and Similar Obligations - Additional Information (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2021
USD ($)
Retirement Benefits [Abstract]  
Defined benefit, pension contributions $ 13
Additional contributions for remainder of fiscal year $ 61
v3.21.1
Post-Retirement and Similar Obligations - Periodic Benefit Costs Net (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Service cost $ 10 $ 12
Interest cost 22 27
Expected return on plan assets (50) (50)
Actuarial loss 35 31
Net Periodic Benefit Cost 17 20
Other Postretirement Benefit Plan    
Defined Benefit Plan Disclosure [Line Items]    
Service cost 1 1
Interest cost 2 3
Expected return on plan assets (2) (2)
Prior service costs (2) (2)
Actuarial loss 1 0
Net Periodic Benefit Cost $ 0 $ 0
v3.21.1
Equity - Additional Information (Details) - USD ($)
$ in Millions
 1 Months Ended 3 Months Ended
Mar. 31, 2021
Mar. 31, 2021
Mar. 31, 2020
Dec. 31, 2020
Class of Stock [Line Items]        
Treasury stock, shares (in shares) 121,188 121,188   413,782
Release of common stock held in trust (in shares)   292,594 0  
Number of shares repurchased during period (in shares) 53,311      
Treasury shares (in shares) 357,146 357,146    
Repurchases of common stock $ 16 $ 16   $ 14
Iberdrola Renewables Holding, Inc        
Class of Stock [Line Items]        
Percentage of equity owned by parent 81.50% 81.50%    
Convertible Preferred Stock        
Class of Stock [Line Items]        
Convertible preferred stock, shares outstanding (in shares) 0 0   0
v3.21.1
Equity - Accumulated Other Comprehensive Gain (Loss) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Balance, beginning of period $ 15,826 $ 15,539
Other comprehensive income (loss), net of tax (26) (21)
Balance, end of period 15,992 15,861
Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, tax (5) (8)
Reclassification to net income of loss on cash flow hedges, tax expense (benefit) (1) 0
Change in revaluation of defined benefit plans    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Balance, beginning of period (12) (12)
Other comprehensive income (loss), net of tax 0 0
Balance, end of period (12) (12)
Loss on nonqualified pension plans    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Balance, beginning of period (20) (7)
Other comprehensive income (loss), net of tax 0 0
Balance, end of period (20) (7)
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 (35) (13)
Other comprehensive income (loss), net of tax (27) (23)
Balance, end of period (62) (36)
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 (44) (63)
Other comprehensive income (loss), net of tax 1 2
Balance, end of period (43) (61)
Loss on derivatives qualifying as cash flow hedges    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Balance, beginning of period (79) (76)
Other comprehensive income (loss), net of tax (26) (21)
Balance, end of period (105) (97)
Accumulated Other Comprehensive Loss    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Balance, beginning of period (111) (95)
Other comprehensive income (loss), net of tax (26) (21)
Balance, end of period $ (137) $ (116)
v3.21.1
Earnings Per Share (Details) - USD ($)
$ / shares in Units, $ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Numerator:    
Net income attributable to AVANGRID $ 334 $ 240
Denominator:    
Weighted average number of shares outstanding - basic (in shares) 309,495,250 309,491,082
Weighted average number of shares outstanding - diluted (in shares) 309,736,266 309,623,573
Earnings per share attributable to AVANGRID    
Earnings Per Common Share, Basic (in dollars per share) $ 1.08 $ 0.78
Earnings Per Common Share, Diluted (in dollars per share) $ 1.08 $ 0.78
v3.21.1
Segment Information - Additional Information (Details)
 3 Months Ended
Mar. 31, 2021
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
v3.21.1
Segment Information - By Segment (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Dec. 31, 2020
Segment Reporting Information [Line Items]      
Revenues $ 1,966 $ 1,789  
Depreciation and amortization 247 251  
Operating income 406 327  
Earnings (losses) from equity method investments 1 (6)  
Interest expense, net of capitalization 73 76  
Income tax expense (benefit) 14 12  
Adjusted net income 354 236  
Capital expenditures 623 742  
Property, plant and equipment 27,168   $ 26,751
Equity method investments 695   668
Total assets 37,768   37,823
Corporate And Eliminations      
Segment Reporting Information [Line Items]      
Revenues 0 0  
Depreciation and amortization 0 0  
Operating income 1 5  
Earnings (losses) from equity method investments 0 0  
Interest expense, net of capitalization 20 7  
Income tax expense (benefit) (19) (1)  
Adjusted net income 2 (8)  
Capital expenditures 0 0  
Property, plant and equipment 9   10
Equity method investments 0   0
Total assets 848   364
Networks      
Segment Reporting Information [Line Items]      
Revenues 1,573 1,461  
Networks | Operating Segments      
Segment Reporting Information [Line Items]      
Revenues 1,573 1,461  
Depreciation and amortization 156 148  
Operating income 313 309  
Earnings (losses) from equity method investments 2 2  
Interest expense, net of capitalization 53 68  
Income tax expense (benefit) 42 43  
Adjusted net income 229 198  
Capital expenditures 531 437  
Property, plant and equipment 17,493   17,079
Equity method investments 134   134
Total assets 25,103   24,592
Renewables      
Segment Reporting Information [Line Items]      
Revenues 393 328  
Renewables | Operating Segments      
Segment Reporting Information [Line Items]      
Revenues 393 328  
Depreciation and amortization 91 103  
Operating income 92 13  
Earnings (losses) from equity method investments (1) (8)  
Interest expense, net of capitalization 0 1  
Income tax expense (benefit) (9) (30)  
Adjusted net income 123 46  
Capital expenditures 92 $ 305  
Property, plant and equipment 9,666   9,662
Equity method investments 561   534
Total assets $ 11,817   $ 12,867
v3.21.1
Segment Information - Reconciliation of Adjusted Net Income to Net Income (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Segment Reporting [Abstract]    
Adjusted Net Income Attributable to Avangrid, Inc. $ 354 $ 236
Adjustments:    
Mark-to-market earnings - Renewables (20) 18
Restructuring charges 0 (3)
Impact of COVED -19 (6) (10)
Income tax impact of adjustments 7 (2)
Net Income Attributable to Avangrid, Inc. $ 334 $ 240
v3.21.1
Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Iberdrola Renovables Energía, S.L.    
Related Party Transaction [Line Items]    
Purchases From $ (2) $ (2)
Iberdrola Financiación, S.A.    
Related Party Transaction [Line Items]    
Purchases From (2) (1)
Iberdrola    
Related Party Transaction [Line Items]    
Purchases From (13) (10)
Vineyard Wind    
Related Party Transaction [Line Items]    
Sales To 4 2
Iberdrola Solutions    
Related Party Transaction [Line Items]    
Sales To 7  
Purchases From (38)  
Other    
Related Party Transaction [Line Items]    
Sales To 1 0
Purchases From $ (1) $ 0
v3.21.1
Related Party Transactions - Additional Information (Details) - USD ($)
 3 Months Ended
Dec. 14, 2020
Mar. 31, 2021
Dec. 31, 2020
Related Party Transaction [Line Items]      
Deposit balance   $ 0 $ 0
Iberdrola Loan | Subordinated Debt      
Related Party Transaction [Line Items]      
Debt prepayment term, period of notice 5 days    
AVANGRID | Iberdrola Loan | Subordinated Debt      
Related Party Transaction [Line Items]      
Face amount of debt $ 3,000,000,000    
Debt instrument, interest rate 0.20%    
Monthly floating interest rate 0.01%    
AVANGRID | Iberdrola Loan | Subordinated Debt | Max.      
Related Party Transaction [Line Items]      
Debt instrument, interest rate 0.25%    
Iberdrola Solutions      
Related Party Transaction [Line Items]      
Notes payable   8,000,000 5,000,000
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
v3.21.1
Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($)
$ in Millions
Mar. 31, 2021
Dec. 31, 2020
Related Party Transaction [Line Items]    
Due from Related Parties   $ 2
Iberdrola    
Related Party Transaction [Line Items]    
Due from Related Parties $ 2  
Owed To (11) (43)
Iberdrola Renovables Energía, S.L.    
Related Party Transaction [Line Items]    
Owed To (2) 0
Iberdrola Financiación, S.A.    
Related Party Transaction [Line Items]    
Owed To (3) (6)
Vineyard Wind    
Related Party Transaction [Line Items]    
Due from Related Parties 4 4
Iberdrola Solutions    
Related Party Transaction [Line Items]    
Due from Related Parties 8 5
Owed To (8)  
Other    
Related Party Transaction [Line Items]    
Due from Related Parties 1 1
Owed To $ 0 $ (1)
v3.21.1
Other Financial Statement Items - Accounts Receivable and Unbilled Revenue (Details) - USD ($)
$ in Millions
Mar. 31, 2021
Dec. 31, 2020
Balance Sheet Related Disclosures [Abstract]    
Trade receivables and unbilled revenues $ 1,418 $ 1,295
Allowance for credit losses (135) (108)
Accounts receivable and unbilled revenues, net $ 1,283 $ 1,187
v3.21.1
Other Financial Statement Items - Allowance For Credit Losses (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Accounts Receivable, Allowance for Credit Loss [Roll Forward]    
Beginning balance $ 135 $ 73
Current period provision 39 19
Write-off as uncollectible (12) (15)
Ending balance $ 108 $ 69
v3.21.1
Other Financial Statement Items - Additional Information (Details) - USD ($)
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Dec. 31, 2020
Dec. 31, 2019
Supplemental Balance Sheet Information [Line Items]        
Allowance for doubtful accounts, deferred payment arrangement $ 135,000,000 $ 73,000,000 $ 108,000,000 $ 69,000,000
Provision for doubtful accounts, accounts receivable 39,000,000 19,000,000    
Prepaid other taxes 145,000,000   135,000,000  
Notes payable 0   309,000,000  
$500 million Credit Facility        
Supplemental Balance Sheet Information [Line Items]        
Face amount of debt 500,000,000      
Deferred Payment Arrangements        
Supplemental Balance Sheet Information [Line Items]        
Accounts receivable 80,000,000   78,000,000  
Allowance for doubtful accounts, deferred payment arrangement 53,000,000   $ 48,000,000  
Provision for doubtful accounts, accounts receivable $ 5,000,000 $ 0    
v3.21.1
Other Financial Statement Items - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($)
$ in Millions
Mar. 31, 2021
Dec. 31, 2020
Property, plant and equipment    
Accumulated depreciation $ 10,028 $ 9,799
Intangible assets    
Accumulated amortization $ 322 $ 319
v3.21.1
Income Tax Expense (Details)
 3 Months Ended
Mar. 31, 2021
Mar. 31, 2020
Income Tax Disclosure [Abstract]    
Effective income tax rate 4.20% 5.00%
v3.21.1
Stock-Based Compensation Expense (Details)
$ / shares in Units, $ in Millions
 1 Months Ended 3 Months Ended
Mar. 15, 2021
installment
$ / shares
shares
Feb. 15, 2021
installment
$ / shares
shares
Mar. 31, 2021
USD ($)
shares
Feb. 28, 2021
shares
Aug. 31, 2020
installment
$ / shares
shares
Mar. 31, 2020
installment
shares
Feb. 29, 2020
installment
shares
Oct. 31, 2018
$ / shares
shares
Mar. 31, 2021
USD ($)
Mar. 31, 2020
USD ($)
Dec. 31, 2020
USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                      
Stock-based compensation expense | $                 $ 4 $ 7  
Performance Shares Units (PSUs)                      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                      
Number of shares granted (in shares) 75,000 1,181,031         208,268        
Number of vesting installments | installment 3 3         3        
Number of shares issued (in shares)     45,661                
Grant date fair value (in dollars per share) | $ / shares $ 36.46 $ 36.46                  
Award requisite service period                 4 years    
Restricted Stock Units (RSUs)                      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                      
Number of shares granted (in shares)         5,000            
Number of vesting installments | installment         3            
Number of shares issued (in shares)       1,697       5,953      
Grant date fair value (in dollars per share) | $ / shares         $ 48.99            
Restricted Stock Units (RSUs) | Executive Officer                      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                      
Number of shares granted (in shares)               8,000      
Grant date fair value (in dollars per share) | $ / shares               $ 47.59      
Phantom Shares                      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                      
Number of shares granted (in shares)           167,060          
Number of vesting installments | installment           3          
Cash used to settle award | $     $ 2                
Share based compensation liability | $     $ 1           $ 1   $ 2
v3.21.1
Variable Interest Entities (Details)
$ in Millions
Feb. 05, 2021
wind_farm
MW
Mar. 31, 2021
USD ($)
Dec. 31, 2020
USD ($)
Variable Interest Entity [Line Items]      
Wind farms expected to be part of Aeolus VII | wind_farm 4    
Proposed wind farm and electricity transmission project capacity (in MW) | MW 688    
Assets of variable interest entities (VIEs)   $ 37,768 $ 37,823
Liabilities of variable interest entities (VIEs)   21,776 21,997
Variable Interest Entity, Primary Beneficiary      
Variable Interest Entity [Line Items]      
Assets of variable interest entities (VIEs)   1,708 1,713
Liabilities of variable interest entities (VIEs)   $ 81 $ 107
v3.21.1
Equity Method Investments (Details)
$ in Millions
 1 Months Ended 3 Months Ended 12 Months Ended
Feb. 05, 2021
MW
Dec. 31, 2020
USD ($)
Dec. 31, 2019
MW
Mar. 31, 2021
USD ($)
a
easement
lease_area
MW
Dec. 31, 2019
USD ($)
Dec. 31, 2018
MW
Schedule of Equity Method Investments [Line Items]            
Number of easements acquired | easement       2    
Number of lease areas | lease_area       2    
Proposed wind farm and electricity transmission project capacity (in MW) | MW 688          
Equity method investments   $ 668   $ 695    
Vineyard Wind Limited Liability Company            
Schedule of Equity Method Investments [Line Items]            
Equity method investment, ownership percentage       50.00%    
Leased are transmission capacity (in MW) | MW       5,000    
Area of land (in acres) | a       166,886    
Proposed wind farm and electricity transmission project capacity (in MW) | MW     804     800
Vineyard Wind Limited Liability Company | Avangrid Renewables            
Schedule of Equity Method Investments [Line Items]            
Equity method investment, ownership percentage     50.00%   50.00%  
Amount funded to date   33     $ 100  
Vineyard Wind, LLC            
Schedule of Equity Method Investments [Line Items]            
Equity method investments   $ 245   $ 274    
Vineyard Wind, LLC | Renewables            
Schedule of Equity Method Investments [Line Items]            
Contributions to equity method investment       $ 281    
v3.21.1
Subsequent Event (Details) - $ / shares
 3 Months Ended
Apr. 13, 2021
Mar. 31, 2021
Mar. 31, 2020
Subsequent Event [Line Items]      
Dividends declared (in dollars per share)   $ 0.44 $ 0.44
Subsequent Event      
Subsequent Event [Line Items]      
Dividends declared (in dollars per share) $ 0.44