Avangrid (AGR) 10-K 1 Mar 21 2020 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Feb. 26, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-37660
Entity Registrant Name	Avangrid, Inc.
Entity Incorporation, State or Country Code	NY
Entity Tax Identification Number	14-1798693
Entity Address, Address Line One	180 Marsh Hill Road
Entity Address, City or Town	Orange,
Entity Address, State or Province	CT
Entity Address, Postal Zip Code	06477
City Area Code	207
Local Phone Number	629-1190
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	AGR
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
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
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 2,374
Entity Common Stock, Shares Outstanding		309,371,591
Documents Incorporated by Reference	Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved. Designated portions of the Proxy Statement relating to the 2021 Annual Meeting of the Shareholders are incorporated by reference into Part III to the extent described therein.
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Central Index Key	0001634997

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Statement [Abstract]
Operating Revenues	$ 6,320	$ 6,336	$ 6,477
Operating Expenses
Purchased power, natural gas and fuel used	1,379	1,509	1,653
Operations and maintenance	2,466	2,305	2,258
Loss from assets held for sale	0	0	16
Depreciation and amortization	987	933	855
Taxes other than income taxes, net	619	591	579
Total Operating Expenses	5,451	5,338	5,361
Operating Income	869	998	1,116
Other Income and (Expense)
Other income (expense)	18	121	(66)
(Losses) earnings from equity method investments	(3)	3	10
Interest expense, net of capitalization	(316)	(310)	(303)
Income Before Income Tax	568	812	757
Income tax expense	29	169	167
Net Income	539	643	590
Net loss (income) attributable to noncontrolling interests	42	24	(3)
Net Income Attributable to Avangrid, Inc.	$ 581	$ 667	$ 587
Earnings Per Common Share, Basic (in dollars per share)	$ 1.88	$ 2.16	$ 1.90
Earnings Per Common Share, Diluted (in dollars per share)	$ 1.88	$ 2.16	$ 1.89
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	309,494,939	309,491,082	309,503,319
Diluted (in shares)	309,559,387	309,514,910	309,712,628

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net Income	$ 539	$ 643	$ 590
Other Comprehensive Income
Gain on defined benefit plans, net of income taxes of $0, $0 and $1, respectively	0	1	3
Amortization of pension cost for nonqualified plans, net of income taxes of $3, $(1) and $0, respectively	(13)	(1)	1
Unrealized loss during the year on derivatives qualifying as cash flow hedges, net of income taxes of $(7), $(9) and $(7), respectively	(22)	(22)	(21)
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes of $2, $3 and $(7), respectively	19	11	(8)
Other Comprehensive Loss	(16)	(11)	(25)
Comprehensive Income	523	632	565
Net loss (income) attributable to noncontrolling interests	42	24	(3)
Comprehensive Income Attributable to Avangrid, Inc.	$ 565	$ 656	$ 562

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Other comprehensive income (loss), defined benefit plan, gain (loss) arising during period, tax	$ 0	$ 0	$ 1
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	(3)	(1)	0
Other comprehensive income (loss), cash flow hedge, gain (loss), before reclassification, tax	(7)	(9)	(7)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	$ 2	$ 3	$ (7)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current Assets
Cash and cash equivalents	$ 1,463	$ 178
Accounts receivable and unbilled revenues, net	1,187	1,082
Accounts receivable from affiliates	12	10
Derivative assets	18	11
Fuel and gas in storage	93	110
Materials and supplies	169	141
Prepayments and other current assets	525	199
Regulatory assets	310	294
Total Current Assets	3,777	2,025
Total Property, Plant and Equipment ($1,637 and $787 related to VIEs, respectively)	26,751	25,196
Operating lease right-of-use assets	153	70
Equity method investments	668	645
Other investments	68	63
Regulatory assets	2,572	2,567
Other Assets
Goodwill	3,119	3,119
Intangible assets	305	314
Derivative assets	79	84
Other	331	311
Total Other Assets	3,834	3,828
Total Assets	37,823	34,394
Current Liabilities
Current portion of debt	313	730
Notes payable	307	560
Interest accrued	70	72
Accounts payable and accrued liabilities	1,453	1,361
Accounts payable to affiliates	50	64
Dividends payable	136	136
Taxes accrued	73	56
Operating lease liabilities	8	12
Derivative liabilities	17	20
Other current liabilities	368	336
Total Current Liabilities	274	242
Total Current Liabilities	3,069	3,589
Regulatory liabilities	3,137	3,281
Other Non-current Liabilities
Deferred income taxes	1,919	1,837
Deferred income	1,204	1,274
Pension and other postretirement	1,007	1,100
Operating lease liabilities	154	65
Derivative liabilities	79	85
Asset retirement obligations	210	190
Environmental remediation costs	292	338
Other	448	380
Total Other Non-current Liabilities	5,313	5,269
Non-current debt	7,478	6,716
Non-current debt to affiliate	3,000	0
Total Non-current Liabilities	18,928	15,266
Total Liabilities	21,997	18,855
Commitments and Contingencies	0	0
Stockholders' Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 309,794,917 and 309,752,140 shares issued; 309,077,300 and 309,005,272 shares outstanding, respectively	3	3
Additional paid-in capital	13,665	13,660
Treasury stock	(14)	(12)
Retained earnings	1,666	1,634
Accumulated other comprehensive loss	(111)	(95)
Total Stockholders’ Equity	15,209	15,190
Noncontrolling interests	617	349
Total Equity	15,826	15,539
Total Liabilities and Equity	$ 37,823	$ 34,394
Common stock issued (in shares)	309,794,917	309,752,140
Common stock, outstanding (in shares)	309,077,300	309,005,272

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Property, plant and equipment	$ 26,751	$ 25,196
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)	309,794,917	309,752,140
Common stock, outstanding (in shares)	309,077,300	309,005,272
Variable Interest Entity, Primary Beneficiary
Property, plant and equipment	$ 1,637	$ 787

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash Flow from Operating Activities
Net income	$ 539	$ 643	$ 590
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	987	933	855
Loss from assets held for sale	0	0	16
Accretion expenses	11	12	12
Regulatory assets/liabilities amortization and carrying cost	(13)	64	73
Pension cost	82	91	123
Earnings from equity method investments	3	(3)	(10)
Distribution of earnings from equity method investments	19	12	14
Unrealized losses (gains) on marked to market derivative contracts	5	(76)	22
Gain from divestment and disposal of property	(10)	(135)	(10)
Deferred taxes	17	164	148
Other non-cash items	(83)	(51)	(27)
Changes in operating assets and liabilities:
Current assets	(173)	126	(117)
Noncurrent assets	(170)	(152)	(87)
Current liabilities	160	(2)	99
Noncurrent liabilities	(86)	(38)	80
Net Cash Provided by Operating Activities	1,288	1,588	1,781
Cash Flow from Investing Activities
Capital expenditures	(2,781)	(2,735)	(1,777)
Contributions in aid of construction	48	74	60
Proceeds from sale of equity method and other investment	238	108	186
Proceeds from sale of property, plant and equipment	7	18	18
Payments to affiliates	(3)	(2)	0
Cash distribution from equity method investments	3	5	4
Other investments and equity method investments, net	(370)	(176)	(45)
Net Cash Used in Investing Activities	(2,858)	(2,708)	(1,554)
Cash Flow from Financing Activities
Non-current debt issuances	1,367	2,137	597
Non-current debt issuance with affiliate	3,000	0	0
Repayments of non-current debt	(1,011)	(346)	(217)
Repayments of other short-term debt, net	(253)	(28)	(201)
Repayments of financing leases	(9)	(27)
Repayments of financing leases			(13)
Repurchase of common stock	(2)	0	(4)
Issuance of common stock	(1)	0	(2)
Distributions to noncontrolling interests	(5)	(63)	(76)
Contributions from noncontrolling interests	312	133	223
Dividends paid	(545)	(545)	(537)
Net Cash Provided by (Used in) Financing Activities, Total	2,853	1,261	(230)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	1,283	141	(3)
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	184	43	46
Cash, Cash Equivalents and Restricted Cash, End of Year	1,467	184	43
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	278	270	224
Cash paid (refunded) for income taxes	$ 8	$ 2	$ (13)

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) $ in Millions		Total	Cumulative Effect, Period of Adoption, Adjustment	Total Stockholders' Equity	Total Stockholders' EquityCumulative Effect, Period of Adoption, Adjustment	Common Stock		Additional paid-in capital	Treasury Stock	Retained Earnings	Retained EarningsCumulative Effect, Period of Adoption, Adjustment	Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss)Cumulative Effect, Period of Adoption, Adjustment	Non-controlling Interests	Non-controlling InterestsCumulative Effect, Period of Adoption, Adjustment
Balance at beginning of period (in shares) at Dec. 31, 2017	[1]					309,005,272
Balance at beginning of period at Dec. 31, 2017		$ 15,090	$ 136	$ 15,071	$ (4)	$ 3		$ 13,653	$ (8)	$ 1,469	$ (3)	$ (46)	$ (1)	$ 19	$ 140
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		590		587						587				3
Other comprehensive income, net of tax		(25)		(25)								(25)
Comprehensive income		565
Dividends declared		(540)		(540)						(540)
Issuance of common stock (in shares)	[1]					81,208
Issuance of common stock		(2)		(2)				1		(3)
Repurchase of common stock (in shares)	[1]					(81,208)
Repurchase of common stock		(4)		(4)					(4)
Stock-based compensation		3		3				3
Distributions to noncontrolling interests		(76)												(76)
Contributions from noncontrolling interests		217		4						4				213
Balance at end of period (in shares) at Dec. 31, 2018	[1]					309,005,272
Balance at end of period at Dec. 31, 2018		15,389	(1)	15,090	(1)	$ 3		13,657	(12)	1,514	11	(72)	$ (12)	299
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		643		667						667				(24)
Other comprehensive income, net of tax		(11)		(11)								(11)
Comprehensive income		632
Dividends declared		$ (545)		(545)						(545)
Release of common stock held in trust (in shares)		0
Stock-based compensation		$ 3		3				3
Distributions to noncontrolling interests		(63)		(4)						(4)				(59)
Contributions from noncontrolling interests		$ 124		(9)						(9)				133
Balance at end of period (in shares) at Dec. 31, 2019		309,005,272				309,005,272	[1]
Balance at end of period at Dec. 31, 2019		$ 15,539	$ (1)	15,190	$ (1)	$ 3		13,660	(12)	1,634	$ (1)	(95)		349
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		539		581						581				(42)
Other comprehensive income, net of tax		(16)		(16)								(16)
Comprehensive income		523
Dividends declared		$ (545)		(545)						(545)
Release of common stock held in trust (in shares)		72,028				72,028	[1]
Issuance of common stock (in shares)	[1]					42,777
Issuance of common stock		$ (1)		(1)				(1)
Repurchase of common stock (in shares)	[1]					(42,777)
Repurchase of common stock		(2)		(2)					(2)
Stock-based compensation		6		6				6
Distributions to noncontrolling interests		(5)								0				(5)
Contributions from noncontrolling interests		$ 312		(3)						(3)				315
Balance at end of period (in shares) at Dec. 31, 2020		309,077,300				309,077,300	[1]
Balance at end of period at Dec. 31, 2020		$ 15,826		$ 15,209		$ 3		$ 13,665	$ (14)	$ 1,666		$ (111)		$ 617
[1]	Par value of share amounts is $.01

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Stockholders' Equity [Abstract]
Other comprehensive income, tax	$ (2)	$ (7)	$ (13)
Dividends declared (in dollars per share)	$ 1.76	$ 1.76	$ 1.744
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01

Background and Nature of Operat

Background and Nature of Operations	12 Months Ended
	Dec. 31, 2020
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 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. 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, S.A. has provided AVANGRID a commitment letter (Iberdrola Funding Commitment Letter), pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration. To the extent AVANGRID wishes to effect a funding transaction under the Iberdrola Funding Commitment Letter in order to pay the Merger Consideration, the specific terms of any such transaction will be negotiated between Iberdrola and AVANGRID on an arm’s length basis and must be approved by both (i) a majority of the members of the unaffiliated committee of the board of directors of AVANGRID, and (ii) a majority of the board of directors of AVANGRID. Under the terms of such commitment letter, Iberdrola S.A. has agreed to negotiate with AVANGRID the specific terms of any transaction effecting such funding commitment promptly and in good faith, with the objective that such terms shall be commercially reasonable and approved by AVANGRID. AVANGRID’s and Merger Sub’s obligations under the Merger Agreement are not conditioned upon AVANGRID obtaining financing. The Merger Agreement provides for certain customary termination rights including the right of either party to terminate the Merger Agreement if the Merger is not completed on or before January 20, 2022 (subject to a three-month extension by either party if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). The Merger Agreement further provides that, upon termination of the Merger Agreement under certain specified circumstances (including if AVANGRID terminates the Merger Agreement due to a change in recommendation of the board of directors of PNMR or if PNMR terminates the Merger Agreement to accept a superior proposal (as defined in the

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP and are presented on a consolidated basis, and therefore include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts have been eliminated in consolidation in all periods presented. Immaterial Corrections to Prior Periods We have identified various immaterial corrections to prior periods primarily related to property, plant and equipment and deferred tax liabilities that originated in prior periods. We evaluated the effects of these corrections on our previously-issued consolidated financial statements, individually and in the aggregate, in accordance with the guidance in ASC Topic 250, Accounting Changes and Error Corrections, ASC Topic 250-10-S99-1, Assessing Materiality, and ASC Topic 250-10-S99-2, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, and concluded that no prior period is materially misstated. Accordingly, we have revised our consolidated financial statements for the prior periods presented herein. The revision decreased retained earnings by $6 million as of December 31, 2018. A summary of the effect of the correction on the consolidated balance sheet as of December 31, 2019 is as follows: As of December 31, 2019 As reported Correction As Revised (Millions) Assets Total Property, Plant and Equipment $ 25,218 $ (22) $ 25,196 Total Assets $ 34,416 $ (22) $ 34,394 Liabilities Other current liabilities $ 334 $ 2 $ 336 Total Current Liabilities $ 3,587 $ 2 $ 3,589 Deferred income taxes $ 1,814 $ 23 $ 1,837 Total Other Non-current Liabilities $ 5,246 $ 23 $ 5,269 Total Non-current Liabilities $ 15,243 $ 23 $ 15,266 Total Liabilities $ 18,830 $ 25 $ 18,855 Equity Retained earnings $ 1,681 $ (47) $ 1,634 Total Stockholders’ Equity $ 15,237 $ (47) $ 15,190 Total Equity $ 15,586 $ (47) $ 15,539 Total Liabilities and Equity $ 34,416 $ (22) $ 34,394 A summary of the effect of the correction on the consolidated statements of income for the year ended December 31, 2019 is as follows: Year Ended December 31, 2019 As reported Correction As Revised (Millions) Operating Revenues $ 6,338 $ (2) $ 6,336 Operations and maintenance $ 2,301 $ 4 $ 2,305 Depreciation and amortization $ 934 $ (1) $ 933 Total Operating Expenses $ 5,335 $ 3 $ 5,338 Operating Income $ 1,003 $ (5) $ 998 Other income $ 119 $ 2 $ 121 Interest expense, net of capitalization $ (306) $ (4) $ (310) Income Before Income Tax $ 819 $ (7) $ 812 Income tax expense $ 143 $ 26 $ 169 Net Income $ 676 $ (33) $ 643 Net Income Attributable to Avangrid, Inc. $ 700 $ (33) $ 667 Earnings per common share, Basic $ 2.26 $ (0.10) $ 2.16 Earnings per common share, Diluted $ 2.26 $ (0.10) $ 2.16 A summary of the effect of the correction on the consolidated statements of income for the year ended December 31, 2018 is as follows: Year Ended December 31, 2018 As reported Correction As Revised (Millions) Operating Revenues $ 6,478 $ (1) $ 6,477 Operations and maintenance $ 2,248 $ 10 $ 2,258 Total Operating Expenses $ 5,351 $ 10 $ 5,361 Operating Income $ 1,127 $ (11) $ 1,116 Income Before Income Tax $ 768 $ (11) $ 757 Income tax expense $ 170 $ (3) $ 167 Net Income $ 598 $ (8) $ 590 Net Income Attributable to Avangrid, Inc. $ 595 $ (8) $ 587 Earnings per common share, Basic $ 1.92 $ (0.02) $ 1.90 Earnings per common share, Diluted $ 1.92 $ (0.03) $ 1.89 A summary of the effect of the correction on the consolidated statements of cash flows for the years ended December 31, 2019 and 2018 is as follows: Years Ended December 31, 2019 2018 (Millions) As Reported Correction As Revised As Reported Correction As Revised Net income $ 676 $ (33) $ 643 $ 598 $ (8) $ 590 Depreciation and amortization $ 934 $ (1) $ 933 $ 855 $ — $ 855 Deferred taxes $ 138 $ 26 $ 164 $ 151 $ (3) $ 148 Current liabilities $ (5) $ 3 $ (2) $ 98 $ 1 $ 99 Net Cash Provided by Operating Activities $ 1,593 $ (5) $ 1,588 $ 1,791 $ (10) $ 1,781 Capital expenditures $ (2,740) $ 5 $ (2,735) $ (1,787) $ 10 $ (1,777) Net Cash Used in Investing Activities $ (2,713) $ 5 $ (2,708) $ (1,564) $ 10 $ (1,554) Cash paid for interest, net of amounts capitalized $ 266 $ 4 $ 270 $ 224 $ — $ 224

Summary of Significant Accounti

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates	Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates Significant Accounting Policies We consider the following policies to be the most significant in understanding the judgments that are involved in preparing our consolidated financial statements: (a) Principles of consolidation We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. We account for investments in common stock where we have the ability to exercise significant influence, but not control, using the equity method of accounting. (b) Revenue recognition We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. Refer to Note 4 for further details. (c) Regulatory accounting We account for our regulated utilities' operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by an independent, third-party regulator; (ii) rates are designed to recover the entity’s specific costs of providing the regulated services or products and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and can be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. We amortize regulatory assets and liabilities and recognize the related expense or revenue in our consolidated statements of income consistent with the recovery or refund included in customer rates. We believe it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates. (d) Business combinations and assets acquisitions (disposals) We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred, including contingent consideration, and the equity interests issued by the acquirer. We measure identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination initially at their fair values at the acquisition date. We record as goodwill the excess of the consideration transferred over the fair value of the identifiable net assets acquired. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. For business combinations, we expense acquisition-related costs as incurred. In contrast to a business combination (disposal), we classify a transaction as an asset acquisition (disposal) when substantially all the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. For asset acquisitions, we capitalize acquisition-related costs as a component of the cost of the assets acquired and liabilities assumed. (e) Noncontrolling interests Noncontrolling interests represent the portion of our net income (loss), comprehensive income (loss) and net assets that is not allocable to us and is calculated based on our ownership percentage. For holdings where the economic allocations are not based pro rata on ownership percentages, we use the balance sheet-oriented hypothetical liquidation at book value (HLBV) method, to reflect the substantive profit sharing arrangement. Under the HLBV method, the amounts we report as "Noncontrolling interests" and "Net income (loss) attributable to noncontrolling interests" in our consolidated balance sheets and consolidated statements of income represent the amounts the noncontrolling interest would hypothetically receive at each balance sheet reporting date under the liquidation provisions of each holding’s ownership agreement assuming we were to liquidate the net assets of the projects at recorded amounts determined in accordance with U.S. GAAP and distribute those amounts to the investors. We determine the noncontrolling interest in our statements of income and comprehensive income as the difference in noncontrolling interests on our consolidated balance sheets at the start, or at inception of the noncontrolling interest if applicable, and end of each reporting period, after taking into account any capital transactions between the holdings and the third party. We report the noncontrolling interest balances in the holdings as a component of equity on our consolidated balance sheets. (f) Equity method investments We account for joint ventures that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as "Earnings (losses) from equity method investments." We recognize dividends received from joint ventures as a reduction in the carrying amount of the investment and not as dividend income. We assess and record an impairment of our equity method investments in earnings for a decline in value that we determine to be other than temporary. (g) Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option to first perform a qualitative assessment to determine whether a quantitative assessment is necessary. If we determine, based on qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass the qualitative assessment, or perform the qualitative assessment but determine it is more likely than not that its fair value is less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four (h) Property, plant and equipment We account for property, plant and equipment at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and add an equal amount to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. We expense project costs during early stage development activities. Once we achieve certain development milestones and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. We periodically review development projects in construction for any indications of impairment. We transfer assets from “Construction work in progress” to “Property, plant and equipment” when they are available for service. We capitalize wind turbine and related equipment costs, other project construction costs and interest costs related to the project during the construction period through substantial completion. We record AROs at the date projects achieve commercial operation. We depreciate the cost of plant and equipment in use on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-55 Hydroelectric power stations 45-90 Wind power stations 25-40 Solar power stations 25 Transport facilities 40-75 Distribution facilities 15-80 Equipment Conventional meters and measuring devices 7-60 Computer software 4-25 Other Buildings 30-82 Operations offices 5-75 Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost of utility plant retired or otherwise disposed to accumulated depreciation. Networks' composite rate of depreciation was 2.9% of average depreciable property for both 2020 and 2019. We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs. Allowance for funds used during construction (AFUDC), applicable to Networks' entities that apply regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. We record the portion of AFUDC attributable to borrowed funds as a reduction of interest expense and record the remainder as other income. (i) Leases We determine if an arrangement is a lease at inception. We classify a lease as a finance lease if it meets any one of specified criteria that in essence transfers ownership of the underlying asset to us by the end of the lease term. If a lease does not meet any of those criteria, we classify it as an operating lease. On our consolidated balance sheets, we include, for operating leases: "Operating lease right-of-use (ROU) assets" and "Operating lease liabilities (current and non-current)"; and for finance leases: finance lease ROU assets in "Other assets" and liabilities in "Other current liabilities" and "Other liabilities." ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize lease ROU assets and liabilities at commencement of an arrangement based on the present value of lease payments over the lease term. Most of our leases do not provide an implicit rate, so we use our incremental borrowing rate based on the information available at the lease commencement date to determine the present value of future payments. A lease ROU asset also includes any lease payments made at or before commencement date, minus any lease incentives received, and includes initial direct costs incurred. We do not record leases with an initial term of 12 months or less on the balance sheet for all classes of underlying assets, and we recognize lease expense for those leases on a straight-line basis over the lease term. We include variable lease payments that depend on an index or a rate in the ROU asset and lease liability measurement based on the index or rate at the commencement date, or upon a modification. We do not include variable lease payments that do not depend on an index or a rate in the ROU asset and lease liability measurement. A lease term includes an option to extend or terminate the lease when it is reasonably certain that we will exercise that option. We recognize lease (rent) expense for operating lease payments on a straight-line basis over the lease term, or for our regulated companies we recognize the amount eligible for recovery under their rate plans, such as actual amounts paid. We amortize finance lease ROU assets on a straight-line basis over the lease term and recognize interest expense based on the outstanding lease liability. We have lease agreements with lease and non-lease components, and account for lease components and associated non-lease components together as a single lease component, for all classes of underlying assets. (j) Impairment of long-lived assets We evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. We are required to recognize an impairment loss if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow (DCF) model, with assumptions consistent with a market participant’s view of the exit price of the asset. (k) Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: • Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. • Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair valu e. (l) Equity investments with readily determinable fair values We measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income. (m) Derivatives and hedge accounting Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met. Derivatives that qualify and are designated for hedge accounting are classified as cash flow hedges. We report the gain or loss on the derivative instrument as a component of Other Comprehensive Income (OCI) and later reclassify amounts into earnings when the underlying transaction occurs, which we present in the same income statement line item as the earnings effect of the hedged item. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, we will discontinue hedge accounting prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, we immediately recognize in earnings hedge gains and losses previously recorded in OCI. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. For our regulated operations, we record changes in the fair value of electric and natural gas hedge contracts derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. (n) Cash and cash equivalents Cash and cash equivalents include cash, bank accounts and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and include those investments in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on our consolidated balance sheets. We classify book overdrafts representing outstanding checks in excess of funds on deposit as “Accounts payable and accrued liabilities” on our consolidated balance sheets. We report changes in book overdrafts in the operating activities section of our consolidated statements of cash flows. (o) Trade receivable and unbilled revenue, net of allowance for credit losses We record trade receivables at amounts billed to customers and we record unbilled revenues based on an estimate of energy delivered or services provided to customers. Certain trade receivables and payables related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances and they are settled on a net basis. We present receivables and payables subject to such agreements on a net basis on our consolidated balance sheets. Trade receivables include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and we classify them as short term. Due to COVID-19, the UIL companies’ regulators require them to offer to customers, through early February 2021, a 24-month repayment plan. We establish our allowance for credit losses, including for unbilled revenue (also referred to as contract assets), by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. Due to our adoption of Accounting Standards Codification (ASC) 326 effective January 1, 2020, we now also consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the trade receivables. We write off amounts when we have exhausted reasonable collection efforts. (p) Variable interest entities An entity is considered to be a variable interest entity (VIE) when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses of or the right to receive benefits from the VIE that could potentially be significant to the VIE. We evaluate whether an entity is a VIE whenever reconsideration events occur as defined by the accounting guidance (See Note 20). We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as noncontrolling interests on our consolidated balance sheets. Subsequently, we use the HLBV method to allocate earnings to the noncontrolling interest, taking into consideration the cash and tax benefits provided to the tax equity investors. (q) Debentures, bonds and bank borrowings We record bonds, debentures and bank borrowings as a liability equal to the proceeds of the borrowings. We treat the difference between the proceeds and the face amount of the issued liability as discount or premium and accrete the amounts as interest expense or income over the life of the instrument. We defer incremental costs associated with the issuance of debt instruments and amortize them over the same period as debt discount or premium. We present bonds, debentures and bank borrowings net of unamortized discount, premium and debt issuance costs on our consolidated balance sheets. (r) Inventory Inventory comprises fuel and gas in storage and materials and supplies. Through our gas operations, we own natural gas that is stored in third-party owned underground storage facilities, which we record as inventory. We price injections of inventory into storage at the market purchase cost at the time of injection, and price withdrawals of working gas from storage at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. We report inventories to support gas operations on our consolidated balance sheets within “Fuel and gas in storage.” We also have materials and supplies inventories that we use for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.” In addition, stand-alone renewable energy credits that are generated or purchased and held for sale are recorded at the lower of cost or net realizable value and are reported on our consolidated balance sheets within “Materials and supplies.” (s) Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to the related utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, we recognize amounts receivable as an offset to expenses in our consolidated statements of income in the period in which we incur the expenses. (t ) Deferred income Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such revenues on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met. (u) Asset retirement obligations We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. We adjust the liability periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. We classify these as accrued removal obligations. (v) Environmental remediation liability In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. We record our environmental liabilities on an undiscounted basis. We expect to pay our environmental liability accruals through the year 2056. (w) Post-employment and other employee benefits We sponsor defined benefit pension plans that cover eligible employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations generally reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. Unrecognized actuarial gains and losses related to the pension and other postretirement benefits plans are amortized over the average remaining service period or 10 years, considering any requirement by the regulators for our Networks subsidiaries. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five-year period. (x) Income taxes We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with U.S. GAAP for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. We defer the investment tax credits (ITCs) when earned and amortize them over the estimated lives of the related assets. We also recognize the income tax consequences of intra-entity transfers of assets other than inventory when the transfer occurs. Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a mor

Revenue

Revenue	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue	Revenue We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale. The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about our reportable segments, refer to Note 24. 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. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to Federal Energy Regulatory Commission (FERC) regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO), or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer. The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service. We record revenue for all of such sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less. For its New York and Connecticut utilities, Networks assesses its DPAs at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result. Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms, other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues. 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 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. There are no material initial incremental costs of obtaining a contract or significant financing elements in any of the arrangements. 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. Certain customers may receive cash credits, which we account for as variable consideration. Renewables estimates those amounts based on the expected amount to be provided to customers and reduces revenues recognized. We believe that there will not be significant changes to our estimates of variable consideration. Other Other, which does not represent a segment, derives its revenues primarily from miscellaneous Corporate revenues including intersegment eliminations, and in 2018 also had revenues from providing natural gas storage services to customers, gas trading operations generally classified as derivative revenue in accordance with the applicable accounting standards and gas trading contracts not classified as derivatives. Contract Costs, Contract Liabilities and Practical Expedient 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 and $12 million at December 31, 2020 and 2019, respectively, and are presented in "Other non-current assets" on our 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 $9 million and $10 million at December 31, 2020 and 2019, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. For both the years ended December 31, 2020 and 2019, we recognized $21 million as revenue related to contract liabilities and for the year ended December 31, 2018, we recognized $13 million. We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs. Revenues disaggregated by major source for our reportable segments for the years ended December 31, 2020, 2019 and 2018 are as follows: Year Ended December 31, 2020 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,642 $ — $ — $ 3,642 Regulated operations – natural gas 1,311 — — 1,311 Nonregulated operations – wind — 822 — 822 Nonregulated operations – solar — 19 — 19 Nonregulated operations – thermal — 39 — 39 Other (a) 58 101 — 159 Revenue from contracts with customers 5,011 981 — 5,992 Leasing revenue 6 — — 6 Derivative revenue — 136 — 136 Alternative revenue programs 157 — — 157 Other revenue 14 15 — 29 Total operating revenues $ 5,188 $ 1,132 $ — $ 6,320 Year Ended December 31, 2019 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,485 $ — $ — $ 3,485 Regulated operations – natural gas 1,479 — — 1,479 Nonregulated operations – wind — 803 — 803 Nonregulated operations – solar — 26 — 26 Nonregulated operations – thermal — 29 — 29 Other (a) 91 62 (12) 141 Revenue from contracts with customers 5,055 920 (12) 5,963 Leasing revenue 6 — — 6 Derivative revenue — 244 — 244 Alternative revenue programs 75 — — 75 Other revenue 28 20 — 48 Total operating revenues $ 5,164 $ 1,184 $ (12) $ 6,336 Year Ended December 31, 2018 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,641 $ — $ — $ 3,641 Regulated operations – natural gas 1,473 — — 1,473 Nonregulated operations – wind — 636 — 636 Nonregulated operations – solar — 17 — 17 Nonregulated operations – thermal — 47 — 47 Nonregulated operations – gas storage — — 10 10 Other (a) 58 (68) 9 (1) Revenue from contracts with customers 5,172 632 19 5,823 Leasing revenue 38 346 — 384 Derivative revenue — 124 10 134 Alternative revenue programs 80 — — 80 Other revenue 20 36 — 56 Total operating revenues $ 5,310 $ 1,138 $ 29 $ 6,477 (a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate, Gas (for 2018 only) and intersegment eliminations. As of December 31, 2020 and 2019, trade receivable balances related to contracts with customers were approximately $1,151 million and $1,050 million, respectively, including $341 million and $345 million of unbilled revenue, which are included in “Accounts receivable and unbilled revenues, net” on our consolidated balance sheets. As of December 31, 2020, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of December 31, 2020 2021 2022 2023 2024 2025 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ 1 $ 1 $ 1 $ — $ — $ 4 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 31 23 13 4 3 5 79 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 40 24 16 14 12 75 182 Total operating revenues $ 72 $ 48 $ 30 $ 19 $ 15 $ 80 $ 265 We do not disclose information about remaining performance obligations for contracts for which we recognize revenue in the amount to which we have the right to invoice (e.g., usage-based pricing terms).

Industry Regulation

Industry Regulation	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Industry Regulation	Industry Regulation Electricity and Natural Gas Distribution – Maine, New York, Connecticut and Massachusetts Each of Networks’ eight regulated utility companies must comply with regulatory procedures that differ in form but in all cases conform to the basic framework outlined below. Generally, tariff reviews cover various years and provide for a reasonable ROE, protection from, and automatic adjustments for, exceptional costs incurred and efficiency incentives. The distribution rates and allowed ROEs for Networks’ regulated utilities in New York are subject to regulation by the New York Public Service Commission (NYPSC), in Maine by the Maine Public Utilities Commission (MPUC), in Connecticut by the Connecticut Public Utilities Regulatory Authority (PURA) and in Massachusetts by the Department of Public Utilities (DPU). The revenues of Networks companies are essentially regulated, being based on tariffs established in accordance with administrative procedures set by the various regulatory bodies. The tariffs applied to the Networks companies are approved by the regulatory commissions of the different states and are based on the cost of providing service. The revenues of each of the Networks companies are set to be sufficient to cover its operating costs, including energy costs, finance costs and the costs of equity, the last of which reflects our capital ratio and a reasonable ROE. Energy costs that are incurred in the New York and New England wholesale markets are passed on to consumers. The difference between energy costs that are budgeted and those that are actually incurred by the utilities is offset by applying compensation procedures that result in either immediate or deferred tariff adjustments. These procedures apply to other costs, which are in most cases exceptional, such as the effects of extreme weather conditions, environmental factors, regulatory and accounting changes, and treatment of vulnerable customers, that are offset in the tariff process. Any New York and Connecticut revenues that allow a utility to exceed target returns, usually the result of better than expected cost efficiency, are generally shared between the utility and its customers, resulting in future tariff reductions. The NYSEG and RG&E rate plans, the Maine distribution rate plan and associated proceedings, the Federal Energy Regulatory Commission (FERC) Transmission Return on Equity (ROE) case, the Connecticut rate plans, Reforming Energy Vision (REV), the storm proceedings in New York and the Tax Act are some of the most important specific regulatory processes that currently affect Networks. 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%, based on an allowed ROE of 9.25% and a 50% equity ratio. The rate increase was effective March 1, 2020. The MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a rolling average period of 18 months, which commenced on March 1, 2020. CMP is meeting the required rolling average benchmarks on all four of these quality measures. 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. CMP Revenue Decoupling Mechanism Investigation On June 9, 2020, the MPUC issued a Notice of Investigation to open an investigation into the effects of the COVID-19 pandemic on customers’ electricity-usage patterns and whether CMP’s RDM should be suspended for the annual distribution rate change that is expected to occur on July 1, 2021, for electricity delivered in calendar year 2020. On June 24, 2020, the MPUC issued a procedural order setting forth initial steps in this proceeding. On July 21, 2020, CMP filed testimony presenting electricity-usage data for its two RDM classes (residential and commercial/industrial) through June 2020, along with testimony explaining the data and the reasons why the current RDM should remain in place without alteration. On August 11, 2020, a technical conference was held and CMP filed electricity-usage data on August 20, 2020. On December 16, 2020, the MPUC issued an order that retains CMP’s RDM but the RDM should be simplified by merging the two RDM classes into a single class. There is no impact to existing RDM balances as a result of the order issued by the MPUC. NYSEG and RG&E Rate Plans 2016 Joint Proposal On June 15, 2016, the NYPSC approved NYSEG's and RG&E's 2016 Joint Proposal for a three-year rate plan for electric and gas service which balanced the varied interests of the signatory parties including but not limited to maintaining the companies’ credit quality and mitigating the rate impacts to customers. The 2016 Joint Proposal reflected many customer benefits including: acceleration of the companies’ natural gas leak prone main replacement programs and increased funding for electric vegetation management to provide continued safe and reliable service. The delivery rate increases for the last year of the 2016 Joint Proposal can be summarized as follows: May 1, 2018 Rate Increase Delivery Rate Increase Utility (Millions) % NYSEG Electric $ 30 4.10 % NYSEG Gas $ 15 7.30 % RG&E Electric $ 26 5.70 % RG&E Gas $ 10 5.20 % The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas was 9.00%. The equity ratio for each company was 48%; however, the equity ratio was set at the actual up to 50% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increased as the ROE increased, with customers receiving 50%, 75% and 90% of earnings in rate year three (May 1, 2018 – April 30, 2019) above 9.75%, 10.25% and 10.75% ROE, respectively. The rate plans also included the implementation of a rate adjustment mechanism (RAM) designed to return or collect certain defined reconciled revenues and costs, new depreciation rates and continuation of the existing RDM for each business. The 2016 Joint Proposal reflected the recovery of deferred NYSEG Electric storm costs of approximately $262 million, of which $123 million is being amortized over ten years and the remaining $139 million is being amortized over five years. The proposal also continues reserve accounting for qualifying Major Storms ($21 million annually for NYSEG Electric and $3 million annually for RG&E Electric). Incremental maintenance costs incurred to restore service in qualifying divisions will be chargeable to the Major Storm Reserve provided they meet certain thresholds. The 2016 Joint Proposal maintained NYSEG’s and RG&E’s current electric reliability performance measures (and associated potential negative revenue adjustments for failing to meet established performance levels) which include the system average interruption frequency index (SAIFI) and the customer average interruption duration index (CAIDI). The 2016 Joint Proposal also modified certain gas safety performance measures at the companies, including those relating to the replacement of leak prone mains, leak backlog management, emergency response and damage prevention. The proposal established threshold performance levels for designated aspects of customer service quality and continued and expanded NYSEG’s and RG&E’s bill reduction and arrears forgiveness Low Income Programs with increased funding levels. The 2016 Joint Proposal provided for the implementation of NYSEG’s Energy Smart Community (ESC) Project in the Ithaca region which serves as a test-bed for implementation and deployment of Reforming the Energy Vision (REV) initiatives. The ESC Project is supported by NYSEG’s planned Distribution Automation upgrades and Advanced Metering Infrastructure (AMI) implementation for customers on circuits in the Ithaca region. The companies also are pursuing Non-Wires Alternative projects as described in the proposal. Other REV-related incremental costs and fees were included in the RAM to the extent cost recovery is not provided for elsewhere. Under the proposal, the RAM was applicable to all customers and serves to return or collect RAM Eligible Deferrals and Costs, including: (1) property taxes; (2) Major Storm deferral balances; (3) gas leak prone pipe replacement; (4) REV costs and fees which are not covered by other recovery mechanisms; and (5) NYSEG Electric Pole Attachment revenues. RG&E implemented a RAM in July 2018 since certain eligibility thresholds were exceeded. The 2016 Joint Proposal provided for partial or full reconciliation of certain expenses including, but not limited to: pensions and other postretirement benefits; property taxes; variable rate debt and new fixed rate debt; gas research and development; environmental remediation costs; major storms; nuclear electric insurance limited credits; economic development; and low income programs. The 2016 Joint Proposal also included a downward-only Net Plant reconciliation. In addition, the 2016 Joint Proposal included downward-only reconciliations for the costs of electric distribution and gas vegetation management, pipeline integrity and incremental maintenance. The 2016 Joint Proposal provided that NYSEG and RG&E continue their electric RDMs on a total revenue per class basis and their gas RDMs on a revenue per customer basis. 2020 Joint Proposal On June 22, 2020, NYSEG and RG&E filed a joint proposal with the NYPSC for a new three-year rate plan (2020 Joint Proposal). On November 19, 2020, the NYPSC approved the 2020 Joint Proposal, with modifications to the rate increases at the two electric businesses. The modifications were made to limit the overall bill impacts, to a level at or below 2% per year, in consideration of the current impacts of COVID-19 on the economic climate. 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% equity ratio; however, for the proposed earnings sharing mechanism, the equity ratio is the lower of the actual equity ratio or 50%. The below table provides a summary of the 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 1 Year 2 Year 3 Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Utility (Millions) % (Millions) % (Millions) % NYSEG Electric $ 34 4.6 % $ 46 5.9 % $ 36 4.2 % NYSEG Gas $ — — % $ 2 0.8 % $ 3 1.6 % RG&E Electric $ 17 3.8 % $ 14 3.2 % $ 16 3.3 % RG&E Gas $ — — % $ — — % $ 2 1.3 % UI, CNG, SCG and BGC Rate Plans Under Connecticut law, The United Illuminating Company’s (UI) retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the Generation Service Charge on their bills. UI has wholesale power supply agreements in place for its entire standard service load for the first half of 2021, 70% of its standard service load for the second half of 2021 and 20% of its standard service load for the first half of 2022. Supplier of last resort service is procured on a quarterly basis and UI has a wholesale power supply agreement in place for the second quarter of 2021. However, from time to time, there are no bidders in the procurement process for supplier of last resort service and UI manages the load directly. In December 2016, the PURA approved new distribution rate schedules for 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% equity ratio, continued UI’s existing ESM pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist. In December 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018 for a three-year rate plan with annual rate increases. 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 a ROE of 9.25% and approximately 52% equity level. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist. In December 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 based on an ROE of 9.30% and an equity ratio of 54% in 2019, 54.50% in 2020 and 55% in 2021. On January 18, 2019, the DPU approved new distribution rates for BGC. The distribution rate increase is based on a 9.70% ROE and 54% 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. REV In April 2014, the NYPSC commenced a proceeding entitled REV, which is a wide-ranging initiative to reform New York State’s energy industry and regulatory practices. REV has been divided into two tracks, Track 1 for Market Design and Technology, and Track 2 for Regulatory Reform. REV and its related proceedings have and will continue to propose regulatory changes that are intended to promote more efficient use of energy, deeper penetration of renewable energy resources such as wind and solar and wider deployment of distributed energy resources (DER), such as micro grids, on-site power supplies and storage. REV is also intended to promote greater use of advanced energy management products to enhance demand elasticity and efficiencies. Track 1 of this initiative involves a collaborative process to examine the role of distribution utilities in enabling market-based deployment of DER to promote load management and greater system efficiency, including peak load reductions. NYSEG is participating in the initiative with other New York utilities. The NYPSC issued a 2015 order in Track 1, which acknowledges the utilities’ role as a Distribution System Platform provider, and required the utilities to file an initial Distribution System Implementation Plan (DSIP) by June 30, 2016, followed by bi-annual updates. The companies filed the initial DSIP, which also included information regarding the potential deployment of Automated Metering Infrastructure (AMI) across its entire service territory. In December 2016, the companies filed a petition to the NYPSC requesting approval for cost recovery associated with the full deployment of AMI. A collaborative associated with this petition began in the first quarter of 2017, was suspended in the second quarter of 2017, subsequently resumed in the first quarter of 2018 and then further suspended and was been included in the companies’ May 20, 2019 rate filing. The companies also filed their first bi-annual update of the DSIP on July 31, 2018 and filed their next bi-annual update on June 30, 2020. Other various proceedings have also been initiated by the NYPSC which are REV related, and each proceeding has its own schedule. These proceedings include the Clean Energy Standard, Value of DER and Net Energy Metering, Demand Response Tariffs and Community Choice Aggregation. As part of the Clean Energy Standard proceeding, all electric utilities were ordered to begin payments to New York State Energy Research and Development Authority (NYSERDA) for RECs and Zero Emissions Credits beginning in 2017. Track 2 of the REV initiative is also underway, and through a NYPSC staff whitepaper review process, is examining potential changes in current regulatory, tariff, market design and incentive structures that could better align utility interests with achieving New York state and NYPSC’s policy objectives. New York utilities will also be addressing related regulatory issues in their individual rate cases. A Track 2 order was issued in May 2016, and includes guidance related to the potential for Earnings Adjustment Mechanisms (EAMs), Platform Service Revenues, innovative rate designs and data utilization and security. The companies, in December 2016, filed a proposal for the implementation of EAMs in the areas of System Efficiency, Energy Efficiency, Interconnections and Clean Air. A collaborative process to review the companies’ petition was suspended in 2017. The approved 2020 Joint Proposal includes EAMs. In March 2017, the NYPSC issued three separate REV-related orders. These orders created a series of filing requirements for NYSEG and RG&E beginning in March 2017 and extending through the end of 2018. The three orders involve: 1) modifications to the electric utilities’ proposed interconnection EAM framework; 2) further DSIP requirements, including filing of an updated DSIP plan by mid-2018 and implementing two energy storage projects at each company by the end of 2018; and 3) Net Energy Metering Transition including implementation of Phase One of the Value of DER. In September 2017, the NYPSC issued another order related to the Value of DER, requiring tariff filings, changes to Standard Interconnection Requirements and planning for the implementation of automated consolidated billing. As of the end of 2018, both NYSEG and RG&E had deployed two energy storage projects each, consistent with the March 2017 NYPSC order requirements. In December 2018, the NYPSC staff submitted whitepapers on standby and buyback service rate design, future value stack compensation and capacity value compensation. The NYPSC ruled on the proposals set forth in the whitepapers on May 16, 2019. NYSEG and RG&E filed proposed standby and buyback rates with the NYPSC in September 2019. On November 25, 2020, DPS Staff, jointly with NYSERDA, issued a whitepaper on further recommendations regarding standby and buyback rates that were based on the electric utilities’ September 23, 2019 filings. Comments on the recommendations in the whitepaper are due February 22, 2021, and reply comments are due March 8, 2021. On April 18, 2019, the NYPSC issued an order on future value stack compensation and capacity value compensation. The order established a new Community Credit in place of the Market Transition Credit for certain CDG projects in NYSEG’s and RGE’s territories and expanded eligibility for Phase One Net Metering for projects that have a rated capacity of 750 kW AC or lower. The changes became effective on June 1, 2019. The NYPSC also issued an order on value stack compensation for high-capacity-factor Resources on December 12, 2019, modifying the treatment of certain high-capacity-factor DER in the Value Stack compensation framework. The modification per the December 12, 2019 Order became effective February 1, 2020. On March 19, 2020, the Commission issued an additional Order regarding Value Stack Compensation. The Order directs National Grid, NYSEG and RGE to reallocate capacity from closed tranches where available capacity remained due to projects being canceled since the issuance of the VDER Compensation Order, and to assign that capacity to a new Community Credit Tranche with compensation at 2 cents per kWh. The utilities must also continue to reallocate capacity to this new Tranche for the next six months when there are cancellations of projects that have received a Market Transition Credit (MTC) or Community Credit allocation. The new provisions per the March 19, 2020 Order became effective May 1, 2020. On May 14, 2020, the Commission issued an Order extending and expanding distributed solar incentives. In addition to authorizing the extension of and additional funding for the NY-Sun program, the Commission modified certain program rules related to the NY-Sun program and the VDER policy. As part of the ordered modifications, the Commission directed the electric utilities with VDER tariffs to add tariff language for a Remote Crediting program that will allow Value-Stack-eligible generation resources to distribute the credits they receive for generation injected into the utility system to the utility bills of multiple, separately sited, non-residential customers. The Commission ordered the utilities to submit tariff leaves that implement the modifications associated with the Remote Crediting program to become effective November 1, 2020. Given the complexity of the program changes, the utilities have petitioned the Commission for tariffs filings to be made on February 15, 2021, with an effective date of March 1, 2021. On July 16, 2020, the Commission issued an Order establishing a net metering successor tariff. The Order continues Phase One NEM for all eligible mass market and commercial projects under 750 kW interconnected after January 1, 2022 and implements a modest customer benefit contribution (CBC) for onsite DERs to address cost recovery of certain public benefit programs. Customers that install DERs interconnected after January 1, 2022 shall be charged a monthly per kW fee based on the nameplate rating of the DER. Draft tariff leaves implementing the Commission’s Order and proposed CBC calculations were filed on November 1, 2020. On April 24, 2018, the NYPSC instituted a proceeding to consider the role of utilities in providing infrastructure and rate design to encourage the expansion electric vehicles and electric vehicle supply equipment. The Commission issued an Order on February 2, 2019 to establish a Direct Current Fast Charger incentive program, with subsequent clarifications provided in Orders issued on July 12, 2019 and March 3, 2020. On July 16, 2020, the NYPSC issued an Order on an electric vehicle make-ready program. The make-ready program will be funded by investor-owned utilities in New York State and creates a cost-sharing program that incentivizes utilities and charging station developers to site electric vehicle charging infrastructure in places that will provide a maximal benefit to consumers. CMP Customer Billing System Investigation On March 1, 2018, the MPUC issued a Notice of Investigation initiating a summary investigation into CMP’s metering, billing and customer communications practices. Due to the highly technical nature of CMP’s customer billing system the MPUC ordered a forensic audit of CMP’s customer billing system to identify any errors that have, or continue to result in billing inaccuracies, and to review CMP’s customer communication practices. On December 20, 2018, the MPUC released the findings of the forensic audit of CMP’s customer billing system and customer communication practices. On January 9, 2020, the hearing examiners issued their report whereby they recommended that the Commission find that the evidence in the record shows that there is no systemic problem within CMP’s metering and billing systems that has caused erroneous high usage on customers’ bills. Instead, the evidence-including the detailed forensic audit conducted by an independent third-party auditor-demonstrates that CMP’s metering and billing systems have been, and continue to be, recording and transmitting customer usage data accurately, and, with the exception of discrete billing calculation and presentation issues, customers’ billed amounts have been accurate. On January 30, 2020, the MPUC Commissioners deliberated and based on the verbal discussion, the Commissioners indicated that CMP’s Metering and Billing system is accurately reporting data; there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. The Commissioners were critical of CMP finding that CMP failed to implement proper testing of the SmartCare system prior to go-live; CMP’s implementation of SmartCare was imprudent; CMP’s SmartCare implementation experienced an unacceptable number of billing errors, delayed or estimated bills, bill presentment issues and unreasonable time required to address these issues; and the implementation issues were compounded by inadequate staffing, resulting in the inability of customers to contact a CMP representative. In its February 19, 2020 order in the CMP’s distribution rate case proceeding discussed above the MPUC imposed a reduction of 100 basis points in ROE, as a management efficiency adjustment, to address concerns with CMP’s customer service performance following the implementation of its new billing system in 2017 and on February 24, 2020 issued an order in the metering and billing investigation. Each order reflected the MPUC’s conclusion that CMP’s Metering and Billing system is accurately reporting data, there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. 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 on all four of these quality measures. On April 27, 2020, the MPUC issued an order requiring that CMP pay for the costs of the metering, billing and customer service practices audit, which were less than $1 million. Tax Cuts and Jobs Act On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the Tax Act) was signed into law. The Tax Act significantly changed the federal taxation of business entities including, among other things, implementing a federal corporate tax rate decrease from 35% to 21% for tax years beginning after December 31, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates 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, DPU and the FERC have instituted separate proceedings in New York, Maine, Connecticut, Massachusetts and the FERC, respectively, to review and address the implications of the Tax Act on the utilities. In New York, the NYPSC issued an order requiring sur-credits to return benefits reflecting the lower effective tax rate of 21% to customers effective October 1, 2018. For NYSEG Gas, RG&E Electric and RG&E Gas the NYPSC also required the sur-credit to include the return to customers of the January - September 2018 Tax Act savings over three years. The remaining deferred amounts associated with the recognition of the effects of the Tax Act are being used as rate moderators in the approved 2020 Joint Proposal. In Connecticut, UI and SCG expect Tax Act savings to be deferred until they are reflected in tariffs in a future rate case, unless PURA determines otherwise. CNG and BGC include Tax Act savings in their current rate plans. In Maine, CMP adjusted rates beginning July 1, 2018 to pass back to customers the Tax Act savings after offsetting for recovery of deferred 2017 storm costs. In its February 19, 2020 order in the CMP’s distribution rate case proceeding discussed above, the MPUC approved CMP’s distribution related accumulated deferred income tax balances associated with the Tax Act as well as the authorized amortization periods for the return of regulatory liabilities and the recovery regulatory assets. At the FERC, CMP transmission and UI transmission adjusted their tariffs in June 2018 to reflect the income statement value of Tax Act savings. Power Tax Audits Previously, CMP, NYSEG and RG&E implemented Power Tax software to track and measure their respective deferred tax amounts. In connection with this change, we identified historical updates needed with deferred taxes recognized by CMP, NYSEG and RG&E and increased our deferred tax liabilities, with a corresponding increase to regulatory assets, to reflect the updated amounts calculated by the Power Tax software. Since 2015, the NYPSC and MPUC accepted certain adjustments to deferred taxes and associated regulatory assets for this item in recent distribution rate cases, resulting in regulatory asset balances of approximately $148 million and $153 million for this item at December 31, 2020 and 2019, respectively. In 2017, audits of the power tax regulatory assets were commenced by the NYPSC and MPUC. On January 11, 2018, the NYPSC issued an order opening an operations audit on NYSEG and RG&E and certain other New York utilities regarding tax accounting. The NYPSC audit report is expected to be completed during 2021. In January 2018, the MPUC published the Power Tax audit report with respect to CMP, which indicated the auditor was unable to verify the asset “acquisition value” used to calculate the Power Tax regulatory asset. The audit report requires that CMP must provide support for the beginning balance of the regulatory assets or it will be unable to recover the value of the assets, which is approximately $11 million, excluding carrying costs. CMP responded to the audit report in its rate case filing by providing additional acquisition value support and, therefore, requested full recovery of the Power Tax regulatory asset. MPUC staff expressed concerns about the value CMP has attributed to this issue. The MPUC had an outside firm conduct an audit of CMP's filing and acquisition values, and the auditor found CMP's information was reasonable. In September 2019, CMP filed a report in response to the audit report and addressed MPUC staff concerns. On December 17, 2019, CMP filed a stipulation with the MPUC providing for recovery of the Power Tax regulatory asset and adjusting the carrying costs values for the period of July 1, 2017 through June 30, 2019. The MPUC approved the stipulation on January 21, 2020, which allowed CMP to start collecting the Power Tax Regulatory asset over the next 32.5 years beginning in July 2020. Minimum Equity Requirements for Regulated Subsidiaries Our regulated utility subsidiaries of Maine and New York (NYSEG, RG&E, CMP and MNG) are each subject to a minimum equity ratio requirement that is tied to the capital structure assumed in establishing revenue requirements. Pursuant to these requirements, each of NYSEG, RG&E, CMP and MNG must maintain a m

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize as regulatory assets incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific regulatory order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in rate base or accruing carrying costs are regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. The total net amount of these items is approximately $1,484 million. 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 December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Pension and other post-retirement benefits cost deferrals $ 105 $ 125 Pension and other post-retirement benefits 927 1,061 Storm costs 451 272 Rate adjustment mechanism 33 79 Revenue decoupling mechanism 58 19 Transmission revenue reconciliation mechanism 31 5 Contracts for differences 86 92 Hardship programs 20 29 Plant decommissioning 3 5 Deferred purchased gas 30 25 Deferred transmission expense 26 11 Environmental remediation costs 247 277 Debt premium 83 97 Unamortized losses on reacquired debt 26 29 Unfunded future income taxes 373 399 Federal tax depreciation normalization adjustment 148 153 Asset retirement obligation 21 17 Deferred meter replacement costs 33 27 COVID-19 cost recovery 1 — Other 180 139 Total regulatory assets 2,882 2,861 Less: current portion 310 294 Total non-current regulatory assets $ 2,572 $ 2,567 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. 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 for 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” 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 AMI meters. This amount is being amortized over the initial depreciation period of related retired meters. "COVID-19 cost recovery" represents deferred COVID-19-related costs in the state of Connecticut based on the order issued by PURA on April 29, 2020, requiring utilities to track COVID-19-related expenses and lost revenue and create a regulatory asset. “Other” includes post-term amortization deferrals and various items subject to reconciliation including hedge losses and deferred property tax. Regulatory liabilities as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Energy efficiency portfolio standard $ 58 $ 72 Gas supply charge and deferred natural gas cost 3 11 Pension and other post-retirement benefits cost deferrals 59 80 Carrying costs on deferred income tax bonus depreciation 34 49 Carrying costs on deferred income tax - Mixed Services 263(a) 11 15 2017 Tax Act 1,435 1,548 Rate change levelization 55 10 Revenue decoupling mechanism 9 17 Accrued removal obligations 1,184 1,173 Asset sale gain account 7 10 Economic development 28 27 Positive benefit adjustment 30 37 Theoretical reserve flow thru impact 10 14 Deferred property tax 31 17 Net plant reconciliation 20 23 Debt rate reconciliation 63 67 Rate refund – FERC ROE proceeding 33 32 Transmission congestion contracts 22 23 Merger-related rate credits 14 16 Accumulated deferred investment tax credits 25 13 Asset retirement obligation 18 14 Earnings sharing provisions 17 28 Middletown/Norwalk local transmission network service collections 18 18 Low income programs 28 33 Non-firm margin sharing credits 14 16 New York 2018 winter storm settlement 9 11 Other 176 149 Total regulatory liabilities 3,411 3,523 Less: current portion 274 242 Total non-current regulatory liabilities $ 3,137 $ 3,281 “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 “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 "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 14 for more details. "Transmission congestion contracts" represents deferral of the Nine Mile 2 Nuclear Plant transmission congestion contract at RGE. 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. In the years ended December 31, 2020 and 2019, respectively, $2 million and $2 million of rate credits were applied against customer bills. "Earning sharing provisions" represents the annual earnings over the earning 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 NYSPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. This balance is being amortized through current rates over an amortization period of three years, beginning in 2020.

Goodwill and Intangible assets

Goodwill and Intangible assets	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible assets	Goodwill and Intangible assets Goodwill by reportable segment as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Networks $ 2,747 $ 2,747 Renewables 372 372 Total $ 3,119 $ 3,119 During 2020, there were no changes in gross amounts and accumulated losses of goodwill for the Networks and Renewables reportable segments. During 2019, Renewables' goodwill was reduced by $8 million as a result of the sale of a 50% interest in the Poseidon projects described in Note 22. Goodwill Impairment Assessment For impairment testing purposes, our reporting units are the same as operating segments, except for Networks, which contains three reporting units, Maine, New York and UIL. Goodwill for the Maine reporting unit is $325 million from the purchase of CMP by Energy East Corporation in 2000. Goodwill for the New York reporting unit is $654 million primarily from the purchase of RG&E by Energy East in 2002. Goodwill for the UIL reporting unit is $1,768 million from the 2015 acquisition of UIL. We perform our annual impairment testing in the fourth quarter, as of October 1. Our qualitative assessment involves evaluating key events and circumstances that could affect the fair value of our reporting units, as well as other factors. Events and circumstances evaluated include macroeconomic conditions, industry, regulatory and market considerations, cost factors and their effect on earnings and cash flows, overall financial performance as compared with projected results and actual results of relevant prior periods, other relevant entity specific events and events affecting a reporting unit. Our quantitative impairment testing includes various assumptions, primarily the discount rate, and forecasted cash flows. We use a discount rate that is developed using market participant assumptions, which consider the risk and nature of the respective reporting unit’s cash flows and the rates of return market participants would require in order to invest their capital in our reporting units. We test the reasonableness of the conclusions of our quantitative impairment testing using a range of discount rates and a range of assumptions for long-term cash flows. We had no impairment of goodwill in 2020 and 2019 as a result of our impairment testing. Intangible assets Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets as of December 31, 2020 and 2019: As of December 31, 2020 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 593 $ (290) $ 303 Other 31 (29) 2 Total Intangible Assets $ 624 $ (319) $ 305 As of December 31, 2019 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 591 $ (289) $ 302 Other 28 (16) 12 Total Intangible Assets $ 619 $ (305) $ 314 Wind development costs, with the exception of future ‘pipeline’ development costs, are amortized on a straight-line basis in accordance with the life of the related assets once placed in service. For the year ended December 31, 2020, amortization expense was for $14 million, and for both the years ended December 31, 2019 and 2018 amortization expense was $15 million. We believe our future cash flows will support the recoverability of our intangible assets. We expect amortization expense for the five years subsequent to December 31, 2020, to be as follows: Year ending December 31, Amount (Millions) 2021 $ 14 2022 $ 13 2023 $ 12 2024 $ 12 2025 $ 12

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment as of December 31, 2020, consisted of: As of December 31, 2020 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 16,364 $ 12,854 $ 29,218 Natural gas transportation, distribution and other 4,637 13 4,650 Other common operating property — 274 274 Total Property, Plant and Equipment in Service 21,001 13,141 34,142 Total accumulated depreciation (5,363) (4,436) (9,799) Total Net Property, Plant and Equipment in Service 15,638 8,705 24,343 Construction work in progress 1,384 1,024 2,408 Total Property, Plant and Equipment $ 17,022 $ 9,729 $ 26,751 Property, plant and equipment as of December 31, 2019, consisted of: As of December 31, 2019 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 15,092 $ 12,360 $ 27,452 Natural gas transportation, distribution and other 4,373 13 4,386 Other common operating property — 258 258 Total Property, Plant and Equipment in Service 19,465 12,631 32,096 Total accumulated depreciation (4,968) (4,090) (9,058) Total Net Property, Plant and Equipment in Service 14,497 8,541 23,038 Construction work in progress 1,271 887 2,158 Total Property, Plant and Equipment $ 15,768 $ 9,428 $ 25,196 Capitalized interest costs were $51 million, $51 million and $26 million for the years ended December 31, 2020, 2019 and 2018, respectively. Accrued liabilities for property, plant and equipment additions were $285 million, $357 million and $154 million as of December 31, 2020, 2019 and 2018, respectively. We impaired or wrote off amounts of $7 million, $11 million and $0 for the years ended December 31, 2020, 2019 and 2018, respectively, resulting from reassessment of the economic feasibility of our various Renewables development projects under construction. Depreciation expense for the years ended December 31, 2020, 2019 and 2018, amounted to $973 million, $918 million and $840 million, respectively.

Asset retirement obligations

Asset retirement obligations	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	Asset retirement obligations AROs are intended to meet the costs for dismantling and restoration work that we have committed to carry out at our operational facilities. The reconciliation of ARO carrying amounts for the years ended December 31, 2020 and 2019 consisted of: (Millions) As of December 31, 2018 $ 217 Liabilities settled during the year (5) Liabilities incurred during the year 6 Accretion expense 12 Revisions in estimated cash flows (a) (40) As of December 31, 2019 $ 190 Liabilities settled during the year (2) Liabilities incurred during the year 9 Accretion expense 11 Revisions in estimated cash flows (a) 2 As of December 31, 2020 $ 210 (a) Represents a reduction in our estimate of expected cash flows required for retirement activities related to our renewable energy facilities. Several of the wind generation facilities have restricted cash for purposes of settling AROs. As of December 31, 2020 and 2019, restricted cash related to AROs was $3 million and $2 million, respectively. These amounts have been included in “Other Assets” on our consolidated balance sheets. Accretion expenses are included in “Operations and maintenance” in our consolidated statements of income. We have AROs for which a liability has not been recognized because the fair value cannot be reasonably estimated due to indeterminate settlement dates, including for the removal of hydroelectric dams due to structural inadequacy or for decommissioning; the removal of property upon termination of an easement, right-of-way or franchise; and costs for abandonment of certain types of gas mains.

Debt

Debt	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Debt	Debt Long-term debt as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 Maturity Dates Balances Interest Rates Balances Interest Rates (Millions) First mortgage bonds - fixed (a) 2021-2049 $ 2,575 1.85%-8.00% $ 2,218 3.07%-8.00% Unsecured pollution control notes - fixed 2023-2029 478 1.40%-3.50% 538 2.00%-3.50% Term loan - variable — 500 2.40% Other various non-current debt - fixed 2021-2050 4,785 1.95%-7.80% 4,228 2.80%-10.48% Unamortized debt issuance costs and discount (47) (38) Total Debt 7,791 7,446 Less: debt due within one year, included in current liabilities 313 730 Total Non-current Debt $ 7,478 $ 6,716 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $7,483 million. Iberdrola Loan On December 14, 2020, AVANGRID and Iberdrola 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 As of December 31, 2020, the Iberdrola Loan had no current maturities and is included in "Non-current debt with affiliate" on our consolidated balance sheet as we do not intend on repaying the Iberdrola Loan with current assets. Proceeds from the Iberdrola Loan of $1,438 million and $300 million, respectively, are included in "cash and cash equivalents" and "prepayments and other current assets" on our consolidated balance sheet as of December 31, 2020. The remainder of the proceeds reduced our commercial paper balance. Other 2020 Long-Term Debt Issuances Company Issue Date Type Amount (Millions) Interest rate Maturity AVANGRID 4/9/2020 Unsecured Notes $ 750 3.20 % 2025 NYSEG (1) 5/1/2020 Pollution Control Bonds $ 200 1.40% - 1.61% 2026 -2029 BGC 9/1/2020 Unsecured Notes $ 25 3.68 % 2050 NYSEG 9/25/2020 Unsecured Notes $ 200 1.95 % 2030 RG&E 11/23/2020 First Mortgage Bonds $ 200 1.85 % 2030 UI 12/1/2020 Unsecured Notes $ 75 2.02 % 2030 CMP 12/15/2020 First Mortgage Bonds $ 50 1.87 % 2030 CNG 12/15/2020 Unsecured Notes $ 30 2.02 % 2030 SCG 12/15/2020 First Mortgage Bonds $ 50 1.87 % 2030 (1) Non-cash remarketing of bonds to reset interest rates. Long-term debt maturities, including sinking fund obligations, due over the next five years consist of: 2021 2022 2023 2024 2025 Total (Millions) $ 313 $ 363 $ 439 $ 612 $ 1,107 $ 2,834 We make certain standard covenants to lenders in our third-party debt agreements, including, in certain agreements, covenants regarding the ratio of indebtedness to total capitalization. A breach of any covenant in the existing credit facilities or the agreements governing our other indebtedness would result in an event of default. Certain events of default may trigger automatic acceleration. Other events of default may be remedied by the borrower within a specified period or waived by the lenders and, if not remedied or waived, give the lenders the right to accelerate. Neither we nor any of our subsidiaries were in breach of covenants or of any obligation that could trigger the early redemption of our debt as of both December 31, 2020 and 2019. Fair Value of Debt As of December 31, 2020 and 2019, the estimated fair value of long-term debt, including the Iberdrola Loan, was $12,166 million and $8,168 million, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rate curve used to make these calculations takes into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value of debt is considered Level 2 within the fair value hierarchy. Short-term Debt AVANGRID has a commercial paper program with a limit of $2 billion which is backstopped by the AVANGRID credit facilities described below. AVANGRID had $307 million and $560 million of notes payable as of December 31, 2020 and 2019, respectively. As of December 31, 2020 and 2019, the balance consisted of $309 million and $562 million, respectively, of commercial paper, presented net of discounts on the balance sheet. As of December 31, 2020 and 2019, the weighted-average interest rate on outstanding commercial paper was 0.32% and 2.07%, respectively. AVANGRID Credit Facility AVANGRID and its subsidiaries, NYSEG, RG&E, CMP, UI, CNG, SCG and BGC have a revolving credit facility with a syndicate of banks, or the AVANGRID Credit Facility, that provides for maximum borrowings of up to $2,500 million in the aggregate. Under the terms of the AVANGRID Credit Facility, each joint borrower has a maximum borrowing entitlement, or sublimit, which can be periodically adjusted to address specific short-term capital funding needs, subject to the maximum limit contained in the agreement. On June 29, 2020, we entered into an amendment to the AVANGRID Credit Facility, which reduced AVANGRID's maximum sublimit from $2,000 million to $1,500 million and added minimum sublimits for each joint borrower other than AVANGRID. Under the AVANGRID Credit Facility, each of the borrowers pays an annual facility fee that is dependent on their credit rating. As of December 31, 2020, the facility fees ranged from 10.0 to 17.5 basis points. The AVANGRID Credit Facility matures on June 29, 2024. 2020 Credit Facility On June 29, 2020, we entered into a revolving credit agreement with several lenders (the 2020 Credit Facility), that provides maximum borrowings up to $500 million. We pay an annual facility fee, which ranges from 15 to 30 basis points, dependent on AVANGRID’s credit rating. As of December 31, 2020, the facility fee is 20 basis points. The 2020 Credit Facility matures on June 28, 2021. We have the right to extend, and the banks are obligated to extend, the commitments and loans outstanding under the facility for one year at a cost of 75 basis points. We may also request an extension of the facility for one year, which the banks may grant at their discretion for a fee that will be determined at the time of the request. As of December 31, 2020, there were no borrowings outstanding under this credit facility. Since our credit facilities are also a backstop to the AVANGRID commercial paper program, the amount available under the facilities as of December 31, 2020 and December 31, 2019 was $2,691 million and $1,938 million, respectively. Iberdrola Group Credit Facility 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 both December 31, 2020 and 2019, there was no outstanding amount under this credit facility.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments and Fair Value Measurements	Fair Value of Financial Instruments and Fair Value Measurements We determine the fair value of our derivative assets and liabilities and non-current equity investments associated with Networks’ activities utilizing market approach valuation techniques: • Our equity and other investments consist of Rabbi Trusts for deferred compensation plans and a supplemental retirement benefit life insurance trust. The Rabbi Trusts primarily include equity securities, 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 12 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 and $6 million as of December 31, 2020 and 2019, respectively and is included in “Other Assets” on our consolidated balance sheets. The financial instruments measured at fair value as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other 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) Derivative financial instruments – Other — — — — — Total $ (24) $ (40) $ (113) $ 81 $ (96) As of December 31, 2019 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 38 $ 13 $ — $ — $ 51 Derivative assets Derivative financial instruments - power $ 4 $ 23 $ 120 $ (54) $ 93 Derivative financial instruments - gas — 40 31 (71) — Contracts for differences — — 2 — 2 Total $ 4 $ 63 $ 153 $ (125) $ 95 Derivative liabilities Derivative financial instruments - power $ (28) $ (43) $ (29) $ 92 $ (8) Derivative financial instruments - gas (4) (26) (5) 33 (2) Contracts for differences — — (94) — (94) Derivative financial instruments – Other — (1) — — (1) Total $ (32) $ (70) $ (128) $ 125 $ (105) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2020, 2019 and 2018 consisted of: (Millions) 2020 2019 2018 Fair value as of January 1, $ 25 $ (15) $ 6 Gains for the year recognized in operating revenues 8 53 18 Losses for the year recognized in operating revenues (2) (2) (9) Total gains or losses for the period recognized in operating revenues 6 51 9 Gains recognized in OCI 1 2 — Losses recognized in OCI (3) (3) (5) Total gains or losses recognized in OCI (2) (1) (5) Net change recognized in regulatory assets and liabilities 6 5 (5) Purchases (2) (22) (6) Settlements (15) 4 (10) Transfers out of Level 3 (a) (5) 3 (4) Fair value as of December 31, $ 13 $ 25 $ (15) Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ 6 $ 51 $ 9 (a) Transfers out of Level 3 were the result of increased observability of market data. 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 December 31, 2020. Index Avg. Max. Min. NYMEX ($/MMBtu) $ 2.53 $ 3.47 $ 1.48 AECO ($/MMBtu) $ 1.45 $ 3.24 $ (0.17) Ameren ($/MWh) $ 26.12 $ 40.53 $ 14.73 COB ($/MWh) $ 33.30 $ 95.00 $ 8.20 ComEd ($/MWh) $ 24.10 $ 39.26 $ 12.65 ERCOT N hub ($/MWh) $ 32.19 $ 196.95 $ 11.25 ERCOT S hub ($/MWh) $ 32.55 $ 203.37 $ 11.41 Indiana hub ($/MWh) $ 28.23 $ 43.58 $ 16.36 Mid C ($/MWh) $ 29.76 $ 95.00 $ 4.00 Minn hub ($/MWh) $ 22.82 $ 37.78 $ 11.52 NoIL hub ($/MWh) $ 24.00 $ 39.01 $ 12.70 PJM W hub ($/MWh) $ 28.46 $ 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 the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years. The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The gas swaps are economic hedges of merchant generation, with decreases in gas prices resulting in unrealized gains and increases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity. Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the models themselves. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products. Transactions are valued in part on the basis of forward price, correlation and volatility curves. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction. The determination of fair value of the CfDs (see Note 12 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 Input December 31, 2020 Risk of non-performance 0.50% - 0.51% Discount rate 0.17% - 0.36% Forward pricing ($ per KW-month) $2.00 - $5.30

Derivative Instruments and Hedg

Derivative Instruments and Hedging	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Derivative Instruments and Hedging Our 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 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 December 31, 2020 and 2019, respectively, including those subject to master netting agreements and the location of the net derivative positions on our consolidated balance sheets: As of December 31, 2020 Current Assets Noncurrent Assets Current Liabilities Noncurrent 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) As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 1 $ 4 $ 1 $ 2 Derivative liabilities (1) (2) (39) (86) — 2 (38) (84) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (1) (1) — — (1) (1) Total derivatives before offset of cash collateral — 2 (39) (85) Cash collateral receivable — — 27 1 Total derivatives as presented in the balance sheet $ — $ 2 $ (12) $ (84) The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of December 31, 2020 and 2019, respectively, consisted of: As of December 31, 2020 2019 (Millions) Wholesale electricity purchase contracts (MWh) 5.6 5.1 Natural gas purchase contracts (Dth) 9.5 8.5 Fleet fuel purchase contracts (Gallons) 2.5 2.2 Derivatives not designated as hedging instruments NYSEG and RG&E have an electric commodity charge that passes costs for the market price of electricity through rates. We use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations. NYSEG and RG&E have purchased gas adjustment clauses that allow us to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities in accordance with the accounting requirements for regulated operations. The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of December 31, 2020 and 2019 and amounts reclassified from regulatory assets and liabilities into income for the years ended 2020, 2019 and 2018 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of For the Year Ended December 31, December 31, 2020 Electricity Natural Gas 2020 Electricity Natural Gas Regulatory assets $ 17 $ 1 Purchased power, natural gas and fuel used $ 55 $ 4 Regulatory liabilities $ — $ — December 31, 2019 2019 Regulatory assets $ 24 $ 4 Purchased power, natural gas and fuel used $ 25 $ 1 Regulatory liabilities $ — $ — 2018 Purchased power, natural gas and fuel used $ (10) $ (1) Pursuant to a PURA order, UI and Connecticut’s other electric utility, 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 December 31, 2020, UI has recorded a gross derivative asset of $2 million ($0 million 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. As of December 31, 2019, UI has recorded a gross derivative asset of $2 million ($0 million of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $92 million, a gross derivative liability of $94 million ($92 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the years ended December 31, 2020, 2019 and 2018, respectively, were as follows: Years Ended December 31, 2020 2019 2018 (Millions) Derivative Assets $ — $ (3) $ (6) Derivative Liabilities $ 6 $ 8 $ 1 Certain foreign currency exchange contracts are not designated as hedging instruments. For the year ended December 31, 2020, we recorded a gain of $4 million related to our foreign currency contracts not designated as hedging instruments, included in "Other income" in our condensed consolidated statements of income. No amounts were recorded for both the years ended December 31, 2019 and 2018. Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2020, 2019 and 2018, respectively, consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2020 Interest rate contracts $ — Interest expense $ 4 $ 316 Commodity contracts (1) Purchased power, natural gas and fuel used 1 1,379 Foreign currency exchange contracts 1 — Total $ — $ 5 2019 Interest rate contracts $ — Interest expense $ 6 $ 310 Commodity contracts — Purchased power, natural gas and fuel used 1 1,509 Foreign currency exchange contracts (1) — Total $ (1) $ 7 2018 Interest rate contracts $ — Interest expense $ 8 $ 303 Commodity contracts (1) Purchased power, natural gas and fuel used — 1,653 Total $ (1) $ 8 (a) Changes in accumulated OCI are reported on a pre-tax basis. On June 20, 2019, Networks entered into a forward contract to hedge the foreign currency exchange risk of approximately $100 million in forecasted capital expenditures through June 2023. The forward foreign currency contracts are designated and qualify as cash flow hedges and are expected to be settled upon the payment to vendors for capital expenditures. The gain or loss on the foreign exchange derivative is reported as a component of accumulated OCI and will be reclassified into earnings over the useful life of the underlying capital expenditures. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $51 million and $55 million as of December 31, 2020 and 2019, respectively. We recorded $4 million, $6 million and $6 million in net derivative losses related to discontinued cash flow hedges during the years ended December 31, 2020, 2019 and 2018, respectively. We will amortize approximately $4 million of discontinued cash flow hedges in 2021. Unrealized losses of $1 million on hedge derivatives are reported in OCI because the forecasted transaction is considered to be probable as of December 31, 2020. We expect that immaterial amounts of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twelve months. (b) Renewables activities The below presented quantitative information includes derivative financial instruments associated with Gas activities, which were sold during 2018. We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets. We also enter into tolling arrangements to sell the output of our thermal generation facilities. Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets. Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms. The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of December 31, 2020 and 2019, respectively, consisted of: As of December 31, 2020 2019 (MWh/Dth in Millions) Wholesale electricity purchase contracts 3 4 Wholesale electricity sales contracts 7 9 Natural gas and other fuel purchase contracts 24 29 Financial power contracts 12 10 Basis swaps - purchases 35 42 Basis swaps - sales 2 1 The fair values of derivative contracts associated with Renewables' activities as of December 31, 2020 and 2019, respectively, consisted of: As of December 31, 2020 2019 (Millions) Wholesale electricity purchase contracts $ 4 $ 10 Wholesale electricity sales contracts 11 4 Natural gas and other fuel purchase contracts — (2) Financial power contracts 66 73 Basis swaps - purchases 7 — Total $ 88 $ 85 The tables below present Renewables' derivative positions as of December 31, 2020 and 2019, respectively, including those subject to master netting agreements and the location of the net derivative position on our consolidated balance sheets: As of December 31, 2020 Current Assets Noncurrent Assets Current Liabilities Noncurrent 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 assets 8 15 2 7 Derivative liabilities (5) (6) (3) (10) 3 9 (1) (3) Total derivatives before offset of cash collateral 27 96 (3) (5) Cash collateral payable (9) (18) — — Total derivatives as presented in the balance sheet $ 18 $ 78 $ (3) $ (5) As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 23 $ 110 $ 42 $ 13 Derivative liabilities (1) (7) (48) (18) 22 103 (6) (5) Designated as hedging instruments Derivative assets — 18 5 4 Derivative liabilities — (9) (13) (6) — 9 (8) (2) Total derivatives before offset of cash collateral 22 112 (14) (7) Cash collateral (payable) receivable (11) (30) 7 6 Total derivatives as presented in the balance sheet $ 11 $ 82 $ (7) $ (1) Derivatives not designated as hedging instruments The effects of trading and non-trading derivatives associated with Renewables' activities for the year ended December 31, 2020, consisted of: Year Ended December 31, 2020 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1) $ — Wholesale electricity sales contracts (1) 6 Financial power contracts 2 — Financial and natural gas contracts — (13) Total loss included in operating revenues $ — $ (7) $ 6,320 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (4) Financial and natural gas contracts — 6 Total gain included in purchased power, natural gas and fuel used $ — $ 2 $ 1,379 Total Loss $ — $ (5) Year Ended December 31, 2019 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1) $ — Wholesale electricity sales contracts 3 40 Financial power contracts (3) 23 Financial and natural gas contracts (1) 1 Total (loss) gain included in operating revenues $ (2) $ 64 $ 6,336 Purchased power, natural gas and fuel used Financial power contracts — (1) Financial and natural gas contracts — 15 Total gain included in purchased power, natural gas and fuel used $ — $ 14 $ 1,509 Total (Loss) Gain $ (2) $ 78 During September 2019, Renewables liquidated a portion of one of its wholesale electricity sales contracts and recorded a gain of $43 million for the year ended December 31, 2019. The effects of trading and non-trading derivatives associated with Renewables activities for the years ended December 31, 2018 consisted of: Years Ended December 31, 2018 (Millions) Trading Non-trading Wholesale electricity purchase contracts $ 4 $ 11 Wholesale electricity sales contracts (2) (15) Financial power contracts — (19) Financial and natural gas contracts 4 — Total Gain (Loss) $ 6 $ (23) Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the years ended December 31, 2020, 2019 and 2018 consisted of: Year Ended December 31, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss (Gain) Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2020 Commodity contracts $ 1 Operating revenues $ 6 $ 6,320 2019 Commodity contracts $ (5) Operating revenues $ 3 $ 6,336 2018 Commodity contracts $ (11) Operating revenues $ (22) $ 6,477 (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 $3 million of gain included in accumulated OCI at December 31, 2020 is expected to be reclassified into earnings within the next twelve months. We recorded immaterial amounts of net derivative losses related to discontinued cash flow hedges for the years ended December 31, 2020, 2019 and 2018. (c) Interest rate contracts AVANGRID uses financial derivative instruments from time to time to alter its fixed and floating rate debt balances or to hedge fixed rates in anticipation of future fixed rate issuances. On January 31, 2020, AVANGRID entered into two treasury locks, with a total notional amount of $600 million, to hedge the issuance of forecasted fixed rate debt. The treasury locks were designated and qualified as cash flow hedges and were settled upon the second quarter debt issuance described in Note 10. The $27 million loss on the treasury locks is reported as a component of accumulated OCI and is being reclassified into earnings during the periods in which the related interest expense of the forecasted debt is incurred. The net loss in accumulated OCI related to previously settled interest rate contracts is $57 million and $38 million as of December 31, 2020 and 2019, respectively. We amortized into income $8 million and $2 million of the loss related to the settled interest rate contracts for the years ended December 31, 2020 and December 31, 2019, respectively. We will amortize approximately $9 million of the net loss on the interest rate contracts during 2021. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2020 and 2019, respectively, consisted of: Years Ended December 31, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2020 Interest rate contracts $ (27) Interest expense $ 8 $ 316 2019 Interest rate contracts $ (24) Interest expense $ 2 $ 310 2018 Interest rate contracts $ (16) Interest expense $ — $ 303 (a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI is being reclassified into earnings over the underlying debt maturity periods which ends 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 December 31, 2020, UI would have had to post an aggregate of approximately $18 million in collateral. We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of a default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. The amount of cash collateral under master netting arrangements that has not been offset against net derivative positions was $18 million and $21 million as of December 31, 2020 and 2019, respectively. Derivative instruments settlements and collateral payments are included throughout the "Changes in operating assets and liabilities" section of operating activities in the 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 December 31, 2020 is $18 million, for which we have posted collateral.

Leases

Leases	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Leases	Leases We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 63 years, some of which may include options to extend the leases for up to 40 years, and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option. The components of lease cost for the years ended December 31, 2020 and 2019 were as follows: For the Year Ended December 31, 2020 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 17 $ 12 Interest on lease liabilities 4 3 Total finance lease cost 21 15 Operating lease cost 16 18 Short-term lease cost 3 5 Variable lease cost — 2 Total lease cost $ 40 $ 40 Balance sheet and other information for the years ended December 31, 2020 and 2019 was as follows: As of December 31, 2020 2019 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 153 $ 70 Operating lease liabilities, current 8 12 Operating lease liabilities, long-term 154 65 Total operating lease liabilities $ 162 $ 77 Finance Leases Other assets $ 162 $ 133 Other current liabilities 8 9 Other non-current liabilities 91 54 Total finance lease liabilities $ 99 $ 63 Weighted-average Remaining Lease Term (years) Finance leases 8.12 7.59 Operating leases 21.38 12.98 Weighted-average Discount Rate Finance leases 3.71 % 5.35 % Operating leases 3.21 % 3.62 % For the years ended December 31, 2020 and 2019, supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2020 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 13 $ 13 Operating cash flows from finance leases $ 3 $ 3 Financing cash flows from finance leases $ 9 $ 27 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ 46 $ 1 Operating leases $ 94 $ 3 As of December 31, 2020, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2021 $ 10 $ 15 2022 5 15 2023 53 13 2024 23 10 2025 2 10 Thereafter 19 182 Total lease payments 112 245 Less: imputed interest (13) (83) Total $ 99 $ 162 Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $47 million and $50 million at December 31, 2020 and December 31, 2019, respectively. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10. The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25-year life of the facility. Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments.
Leases	Leases We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 63 years, some of which may include options to extend the leases for up to 40 years, and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option. The components of lease cost for the years ended December 31, 2020 and 2019 were as follows: For the Year Ended December 31, 2020 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 17 $ 12 Interest on lease liabilities 4 3 Total finance lease cost 21 15 Operating lease cost 16 18 Short-term lease cost 3 5 Variable lease cost — 2 Total lease cost $ 40 $ 40 Balance sheet and other information for the years ended December 31, 2020 and 2019 was as follows: As of December 31, 2020 2019 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 153 $ 70 Operating lease liabilities, current 8 12 Operating lease liabilities, long-term 154 65 Total operating lease liabilities $ 162 $ 77 Finance Leases Other assets $ 162 $ 133 Other current liabilities 8 9 Other non-current liabilities 91 54 Total finance lease liabilities $ 99 $ 63 Weighted-average Remaining Lease Term (years) Finance leases 8.12 7.59 Operating leases 21.38 12.98 Weighted-average Discount Rate Finance leases 3.71 % 5.35 % Operating leases 3.21 % 3.62 % For the years ended December 31, 2020 and 2019, supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2020 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 13 $ 13 Operating cash flows from finance leases $ 3 $ 3 Financing cash flows from finance leases $ 9 $ 27 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ 46 $ 1 Operating leases $ 94 $ 3 As of December 31, 2020, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2021 $ 10 $ 15 2022 5 15 2023 53 13 2024 23 10 2025 2 10 Thereafter 19 182 Total lease payments 112 245 Less: imputed interest (13) (83) Total $ 99 $ 162 Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $47 million and $50 million at December 31, 2020 and December 31, 2019, respectively. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10. The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25-year life of the facility. Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingent Liabilities	Commitments and Contingent Liabilities We are party to various legal disputes arising as part of our normal business activities. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency. Transmission - ROE Complaint – CMP and UI On September 30, 2011, the Massachusetts Attorney General, DPU, PURA, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a joint complaint with the FERC, pursuant to sections 206 and 306 of the Federal Power Act, against several New England Transmission Owners (NETOs) claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE with refunds to customers for the 15-month refund periods beginning October 1, 2011 (Complaint I), December 27, 2012 (Complaint II), July 31, 2014 (Complaint III) and April 29, 2016 (Complaint IV). On October 16, 2014, the FERC issued its decision in Complaint I setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners. CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $26 million and $7 million, respectively, as of December 31, 2020, which has not changed since December 31, 2019, except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge would be an additional aggregate reserve for Complaints II and III of $17 million, which is based upon currently available information for these proceedings. Following various intermediate hearings, orders and appellate decisions, on October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs’ transmission formula rate on file at the FERC (the October 2018 Order). Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019 and replied to the initial briefs on March 8, 2019. On November 21, 2019, the FERC issued rulings on two complaints challenging the base return on equity for Midcontinent Independent System Operator, or MISO transmission owners. These rulings established a new zone of reasonableness based on equal weighting of the DCF and capital-asset pricing model for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing of this decision, which was granted. On May 21, 2020, FERC issued a ruling, which, among other things, adjusted the methodology to determine the MISO transmission owners’ ROE, resulting in an increase in ROE from 9.88% to 10.02% by utilizing the risk premium model in addition to the DCF model and capital-asset pricing model under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. We cannot predict the outcome of these proceedings, including the potential impact the MISO transmission owners' ROE proceeding may have in establishing a precedent for our pending four Complaints. California Energy Crisis Litigation Two California agencies brought a complaint in 2001 against a long-term PPA entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the PPA 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 PPAs unjust and unreasonable. However, the proposed ruling did conclude that the price of the PPAs 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. Gas Storage Indemnification Claims On May 1, 2018, ARHI closed a transaction to sell our gas storage business to Amphora Gas Storage USA, LLC (Amphora). On October 30, 2019, ARHI received notice of a claim for indemnification from Amphora under the purchase agreement with respect to such sale in the amount of approximately $20 million related to, among other things, certain alleged violations of occupational, health and safety requirements, the condition and sufficiency of assets and a third party intellectual property infringement claim. In December 2020, ARHI and Amphora reached a settlement agreement to resolve the claim with ARHI paying Amphora $5 million and Amphora releasing ARHI and AVANGRID of all claims related to the 2018 sale of our gas business. 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. Power, Gas and Other Arrangements Power and Gas Supply Arrangements – Networks NYSEG and RG&E are the providers of last resort for customers. As a result, the companies buy physical energy and capacity from the NYISO. In accordance with the NYPSC's February 26, 2008 Order, NYSEG and RG&E are required to hedge on behalf of non-demand billed customers. The physical electric capacity purchases we make from parties other than the NYISO are to comply with the hedge requirement for electric capacity. The companies enter into financial swaps to comply with the hedge requirement for physical electric energy purchases. Other purchases, from some Independent Power Producers (IPPs) and the New York Power Authority, are from contracts entered into many years ago when the companies made purchases under contract as part of their supply portfolio to meet their load requirement. More recent IPP purchases are required to comply with the companies’ Public Utility Regulatory Policies Act (PURPA) purchase obligation. NYSEG, RG&E, SCG, CNG and BGC (collectively, the Regulated Gas Companies) satisfy their natural gas supply requirements through purchases from various producers and suppliers, withdrawals from natural gas storage, capacity contracts and winter peaking supplies and resources. The Regulated Gas Companies operate diverse portfolios of gas supply, firm transportation capacity, gas storage and peaking resources. Actual gas costs incurred by each of the Regulated Gas Companies are passed through to customers through state regulated purchased gas adjustment mechanisms, subject to regulatory review. The Regulated Gas Companies purchase the majority of their natural gas supply at market prices under seasonal, monthly or mid-term supply contracts and the remainder is acquired on the spot market. The Regulated Gas Companies diversify their sources of supply by amount purchased and location and primarily acquire gas at various locations in the U.S. Gulf of Mexico region, in the Appalachia region and in Canada. The Regulated Gas Companies acquire firm transportation capacity on interstate pipelines under long-term contracts and utilize that capacity to transport both natural gas supply purchased and natural gas withdrawn from storage to the local distribution system. The Regulated Gas Companies acquire firm underground natural gas storage capacity using long-term contracts and fill the storage facilities with gas in the summer months for subsequent withdrawal in the winter months. Winter peaking resources are primarily attached to the local distribution systems and are either owned or are contracted for by the Regulated Gas Companies, each of which is a Local Distribution Company. Each Regulated Gas Company owns or has rights to the natural gas stored in an LNG facility directly attached to its distribution system. Other arrangements include contractual obligations for property, plant and equipment, material and services on order but not yet delivered at December 31, 2020. Power, Gas and Other Arrangements – Renewables Gas purchase commitments consist of firm transport capacity to fuel the Cogen and Peaking gas generators. Power purchase commitments include the following: (i) a 55 MW Biomass PPA for 12 years (one year remaining) with a guaranteed output of 34.4 MW flat and a schedule of fixed price rates depending on season and time of day, (ii) long-term firm transmission agreements with fixed monthly capacity payments that allow the delivery of electricity from wind and thermal generation sources to various customers and (iii) a 95.6 MW (average) three-year purchase of hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2019 and expiring in 2021) and (iv) a five-year purchase of 52 MW (average) hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2019 and expiring in 2023). Power sales commitments include: (i) a 55 MW Biomass off-take agreement for 12 years (one year remaining) with guaranteed annual production of 34.4 MW flat with a schedule of fixed price rates depending on season and time of day, (ii) a retail renewable power sales agreement for 12 MW (average) expiring in 2026, (iii) fixed price, fixed volume power sales off the Klamath Cogen facility, (iv) a seasonal tolling arrangement off the Klamath peaking facility with fixed capacity charges through 2024; (v) fixed price, fixed volume renewable energy credit sales off merchant wind facilities, (vi) sales of merchant wind farm capacity to various ISOs and sales of ancillary services (e.g., regulation and frequency response, generator imbalance, etc.) to third parties from Renewables’ Balancing Authority. In June 2020, Renewables entered into a Payment In Lieu of Taxes (PILOT) agreement related to two of its projects with Torrance County, New Mexico. The agreement requires PILOT payments to Torrance County through 2049. No payments are due until 2021. Renewables also has easement contracts which are included in the table below. Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2020 consisted of: Year Purchases Sales (Millions) 2021 $ 889 $ 178 2022 135 103 2023 74 68 2024 48 41 2025 45 32 Thereafter 934 54 Totals $ 2,125 $ 476 Guarantee Commitments to Third Parties As of December 31, 2020, we had approximately $678 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding, including approximately $88 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 December 31, 2020, neither we nor our subsidiaries have any liabilities recorded for these instruments.

Environmental Liabilities

Environmental Liabilities	12 Months Ended
	Dec. 31, 2020
Environmental Remediation Obligations [Abstract]
Environmental Liabilities	Environmental Liabilities Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies. Waste sites The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-six waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-six sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; five sites are included in Maine’s Uncontrolled Sites Program; one site is included in the Brownfield Cleanup Program and one site is included on the Massachusetts Non-Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, six of the twenty-six sites are also included on the National Priorities list. Any liability may be joint and several for certain sites. We have recorded an estimated liability of $6 million related to twelve of the twenty-six sites. We have paid remediation costs related to the remaining fourteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $9 million related to another twelve sites where we believe it is probable that we will incur remediation and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. Our estimate for costs to remediate these sites ranges from $13 million to $21 million as of December 31, 2020. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the allocation of the clean-up costs. Manufactured Gas Plants We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Six sites are included in the New York State Registry; three sites are included in the New York State Department of Environmental Conservation Multi-Site Order on Consent; three sites are part of Maine’s Voluntary Response Action Program with two such sites part of Maine’s Uncontrolled Sites Program and one site is pending application into the Brownfield Cleanup Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites. Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $177 million to $294 million as of December 31, 2020. Our estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial actions, changes in technology relating to remedial alternatives and changes to current laws and regulations. Certain of our Connecticut and Massachusetts regulated gas companies own or have previously owned properties where MGPs had historically operated. MGP operations have led to contamination of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is regulated by the federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations. Each of the companies has or had an ownership interest in one or more such properties contaminated as a result of MGP-related activities. Under the existing regulations, the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated. Finally, at some of these sites, the scope of the contamination has not yet been fully characterized; no liability was recorded related to these sites as of December 31, 2020 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites. As of December 31, 2020 and 2019, the liability associated with our MGP sites in Connecticut was $96 million and $97 million, respectively, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates. Our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $300 million and $349 million as of December 31, 2020 and 2019, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2056. FirstEnergy NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at sixteen former MGP sites, which are included in the discussion above. In July 2011, the District Court issued a decision and order in NYSEG’s favor, requiring FirstEnergy to pay NYSEG approximately $60 million for past and future clean-up costs at the sixteen sites in dispute. On September 9, 2011, FirstEnergy paid NYSEG $30 million, representing their share of past costs of $27 million and pre-judgment interest of $3 million. FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the District Court’s decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22 million, excluding interest, and reducing FirstEnergy’s allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in November 2014. FirstEnergy remains liable for a substantial share of clean up expenses at nine MGP sites. Based on current projections, FirstEnergy’s share is estimated at approximately $19 million. This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG customers. English Station In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then owners of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut related to environmental remediation at the English Station site. This proceeding was stayed in 2014 pending resolutions of other proceedings before the 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. 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 December 31, 2020 and 2019, the amount reserved for this matter was $22 million and $16 million, respectively. We cannot predict the outcome of this matter . On April 24, 2020, ACV Environmental Services Company (ACV) filed a lawsuit in Connecticut Superior Court against UI arising out of a contract dispute for services rendered by ACV in the demolition of the Station B at the English Station site. The complaint seeks damages in the amount of $5 million on claims of breach of contract, breach of the covenant of good faith and fair dealing, quantum merit, and unjust enrichment. The claims arise from the alleged non-payment of certain change order requests. The parties have agreed to attempt to mediate this matter during the first half of 2021. We cannot predict the outcome of this matter.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Upon enactment of the Tax Act, the Company remeasured its existing deferred income tax balances as of December 31, 2017 to reflect the decrease in the corporate income tax rate from 35% to 21%, which resulted in a material decrease to its net deferred income tax liability balances based on reasonable estimates that could be determined at that time. The Company’s non-regulatory businesses recorded a corresponding net increase or decrease to income tax expense, while the utility operations recorded corresponding regulatory liabilities or assets to the extent that such amounts are probable of settlement or recovery through customer rates. The amount and timing of potential settlements of the established net regulatory liabilities are determined by the regulated utilities’ respective rate regulators and IRS Normalization rules. As of December 31, 2018, the Company has completed the measurement and accounting of certain effects of the Tax Act which have been reflected in the consolidated financial statements. On December 20, 2019, the Setting Every Community up for Retirement Enhancement Act of 2019, was signed into law that extended the PTC and ITC options for wind facilities to 60% of the full credit for facilities commencing construction in 2020, leaving in place phased down credits for projects commencing in years prior to 2020. The 2020 Consolidated Appropriations Act provides extensions to renewable income tax incentives. Onshore and offshore wind projects may now claim a 60% PTC for projects commencing construction in 2020 and 2021. In addition, offshore wind may now elect to claim a 30% ITC for projects commencing construction through 2025. Onshore wind can claim an 18% ITC for projects commencing construction in 2020 or 2021, with no ITC thereafter. Solar projects commencing construction before 2020 may claim a 30% ITC. Solar projects that commence construction from 2020-2022 may claim a 26% ITC, projects commencing construction in 2023 may claim a 22% ITC and projects commencing thereafter may claim a 10% ITC. The ITC statutes require solar projects be completed by the end of 2025 in order to claim the applicable ITCs. The Internal Revenue Service (IRS) provided continuity safe harbor guidance that requires renewable projects to be completed within four years of the year construction commences. Any projects that do not meet this requirement will fall outside of the safe harbor and be subject to IRS scrutiny with regard to the date construction commenced. In 2020, the IRS allowed projects beginning construction in 2016 or 2017 an additional year (five years total) to complete construction. In late December 2020, the IRS issued a notice giving onshore wind projects on federal lands, with transmission permit requirements, and offshore wind projects 10 years to complete construction. During 2020, we received orders to begin returning to customer both protected and unprotected excess ADIT from the 2017 Tax Act. Such amounts are subject to terms of the various state regulators in which we do business while meeting the requirements of normalization for both ARAM and RSG methodologies. We have accounted for those jurisdictions which have issued orders to unit operations. However, not all unit operations have been issued orders as of 2020. Current and deferred taxes charged to expense for the years ended December 31, 2020, 2019 and 2018 consisted of: Years Ended December 31, 2020 2019 2018 (Millions) Current Federal $ 3 $ 11 $ 17 State 9 (6) 2 Current taxes charged to expense 12 5 19 Deferred Federal 67 164 231 State 38 58 (13) Deferred taxes charged to expense 105 222 218 Production tax credits (87) (57) (68) Investment tax credits (1) (1) (2) Total Income Tax Expense $ 29 $ 169 $ 167 The differences between tax expense per the statements of income and tax expense at the 21% statutory federal tax rate for the years ended December 31, 2020, 2019 and 2018 consisted of: Years Ended December 31, 2020 2019 2018 (Millions) Tax expense at federal statutory rate $ 119 $ 170 $ 159 Depreciation and amortization not normalized (13) (23) (5) Investment tax credit amortization (1) (1) (2) Tax return related adjustments 1 (2) (6) Production tax credits (87) (57) (68) Tax equity financing arrangements 1 8 — Federal tax rate impact on held for sale classification — — 21 State tax expense (benefit), net of federal benefit 37 41 (9) Excess ADIT amortization (42) — — Tax Act - remeasurement — — 46 Other, net 14 33 31 Total Income Tax Expense $ 29 $ 169 $ 167 Deferred tax assets and liabilities as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Deferred Income Tax Liabilities (Assets) Property related $ 4,147 $ 4,007 Unfunded future income taxes 100 101 Federal and state tax credits (731) (632) Federal and state NOL’s (1,047) (981) Joint ventures/partnerships 167 136 Nontaxable grant revenue (311) (335) Pension and other post-retirement benefits 22 43 Tax Act - tax on regulatory remeasurement (382) (409) Valuation allowance 81 48 Other (127) (141) Deferred Income Tax Liabilities $ 1,919 $ 1,837 Deferred tax assets $ 2,598 $ 2,498 Deferred tax liabilities 4,517 4,335 Net Accumulated Deferred Income Tax Liabilities $ 1,919 $ 1,837 As of December 31, 2020, we had gross federal tax net operating losses of $3.8 billion, federal PTCs and ITCs, federal R&D tax credits and other federal credits of $695 million, state tax effected net operating losses of $324 million in several jurisdictions and miscellaneous state tax credits of $142 million available to carry forward and reduce future income tax liabilities. For federal purposes, we recognized a valuation allowance of $16 million, and for state purposes, we recognized a valuation allowance of $65 million. The federal net operating losses begin to expire in 2028, while the federal tax credits begin to expire in 2023. The more significant state net operating losses begin to expire in 2021. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that all or a portion of a tax benefit will not be realized. The valuation allowance for deferred tax assets as of December 31, 2020 and 2019 was $81 million and $48 million, respectively. Valuation allowances have been established on various federal tax credits, state net operating losses and state tax credit carryforwards. The Company has recorded a federal valuation allowance on its federal tax credit carryforwards of $16 million and has recorded a state valuation allowance on its state net operating losses and state tax credit carryforwards of $65 million. The $33 million increase in valuation allowance from 2019 to 2020 includes an increase of $12 million for additional valuation allowance on Federal tax credit carryforwards and an increase of $21 million on state net operating losses and state tax credits. The reconciliation of unrecognized income tax benefits for the years ended December 31, 2020, 2019 and 2018 consisted of: Years ended December 31, 2020 2019 2018 (Millions) Beginning Balance $ 148 $ 153 $ 45 Increases for tax positions related to prior years 11 14 111 Increases for tax positions related to current year — 16 — Decreases for tax positions related to prior years (32) (18) (3) Reduction for tax position related to settlements with taxing authorities — (17) — Ending Balance $ 127 $ 148 $ 153 Unrecognized income tax benefits represent income tax positions taken on income tax returns but not yet recognized in the consolidated financial statements. The accounting guidance for uncertainty in income taxes provides that the financial effects of a tax position shall initially be recognized when it is more likely than not based on the technical merits the position will be sustained upon examination, assuming the position will be audited and the taxing authority has full knowledge of all relevant information. Accruals for interest and penalties on tax reserves were immaterial for the years ended December 31, 2020, 2019 and 2018. If recognized, $107 million of the total gross unrecognized tax benefits would affect the effective tax rate. It is estimated that no unrecognized tax benefits are anticipated to result in a net increase or decrease within twelve months of December 31, 2020. AVANGRID and its subsidiaries, without ARHI, have been audited for the federal tax years 1998 through 2009. The results of these audits, net of reserves already provided, were immaterial. Tax years 2010 and forward are open for potential federal adjustments. All New York state returns, which were filed without ARHI, are closed through 2011 and Maine state returns are closed through 2015. All federal tax returns filed by ARHI from the periods ended March 31, 2004, to December 31, 2009, are closed for adjustment. All New York combined state returns are closed for adjustment through 2011. Generally, the adjustment period for the individual states we filed in is at least as long as the federal period. As of December 31, 2020, UIL is subject to audit of its federal tax return for years 2014 through its short period 2015. UIL's short period ending in 2015 is open and subject to Connecticut audit.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
Post-retirement and Similar Obligations	Post-retirement and Similar Obligations AVANGRID and its subsidiaries sponsor a number of retirement benefit plans. The plans include qualified defined benefit pension plans, supplemental non-qualified pension plans, defined contribution plans and other postretirement benefit plans for eligible employees and retirees. Eligibility and benefits vary depending on each plan's design. For example, certain benefits are based on years of service and final average compensation while others may use a cash balance formula that calculates benefits using a percentage of annual compensation. Qualified Retirement Benefit Plans As of December 31, 2020 and 2019, our obligations and funded status consisted of: Pension Benefits Postretirement Benefits As of December 31, 2020 2019 2020 2019 (Millions) Change in benefit obligation Benefit Obligation as of January 1, $ 3,669 $ 3,374 $ 439 $ 425 Service cost 47 41 3 3 Interest cost 107 130 13 16 Plan amendments 7 (2) — — Actuarial loss 236 347 29 26 Curtailments (21) — — — Benefits paid (226) (221) (32) (31) Benefit Obligation as of December 31, 3,819 3,669 452 439 Change in plan assets Fair Value of Plan Assets as of January 1, 2,848 2,544 155 148 Actual return on plan assets 388 460 26 22 Employer contributions 84 65 18 16 Curtailments (2) — — — Benefits paid (226) (221) (32) (31) Fair Value of Plan Assets as of December 31, 3,092 2,848 167 155 Funded Status as of December 31, $ (727) $ (821) $ (285) $ (284) During 2020, the pension benefit obligation had an actuarial loss of $236 million, primarily due to a $276 million loss from decreases in discount rates. The only significant plan change in 2020 was an agreement to freeze the UI union pension plan. There were no significant gains or losses relating to the postretirement benefit obligations. During 2019, the pension benefit obligation had an actuarial loss of $347 million, primarily due to a $384 million loss from decreases in discount rates. There were no significant plan design changes in 2019. There were no significant gains or losses relating to the postretirement benefit obligations. As of December 31, 2020 and 2019, funded status amounts recognized on our consolidated balance sheets consisted of: Pension Benefits Postretirement Benefits As of December 31, 2020 2019 2020 2019 (Millions) Current liabilities $ — $ — $ (5) $ (5) Non-current liabilities (727) (821) (280) (279) Total $ (727) $ (821) $ (285) $ (284) We have determined that Networks’ regulated operating companies are allowed to defer as regulatory assets or regulatory liabilities items that would have otherwise been recorded in accumulated OCI pursuant to the accounting requirements concerning defined benefit pension and other postretirement plans. Amounts recognized as a component of regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2020 and 2019 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2020 2019 2020 2019 (Millions) Net loss $ 610 $ 706 $ 14 $ 13 Prior service cost (credit) $ 10 $ 4 $ (8) $ (21) Amounts recognized in OCI for ARHI for the years ended December 31, 2020 and 2019, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2020 2019 2020 2019 (Millions) Net loss (gain) $ 21 $ 23 $ (7) $ (8) Our accumulated benefit obligation (ABO) for all qualified defined benefit pension plans was $3,629 million and $3,451 million as of December 31, 2020 and 2019, respectively. As of December 31, 2020 and 2019, the projected benefit obligation (PBO) and the ABO exceeded the fair value of pension plan assets for all of our qualified plans, and the aggregate PBO and ABO and the fair value of plan assets for our underfunded qualified plans consisted of: PBO in excess of plan assets As of December 31, 2020 2019 (Millions) Projected benefit obligation $ 3,819 $ 3,669 Fair value of plan assets $ 3,092 $ 2,848 ABO in excess of plan assets As of December 31, 2020 2019 (Millions) Accumulated benefit obligation $ 3,629 $ 3,451 Fair value of plan assets $ 3,092 $ 2,848 As of December 31, 2020 and 2019, the accumulated postretirement benefits obligation for all qualified plans exceeded the fair value of plan assets. Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2020, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2020 2019 2018 2020 2019 2018 (Millions) Net Periodic Benefit Cost: Service cost $ 46 $ 41 $ 44 $ 3 $ 3 $ 4 Interest cost 106 128 126 13 16 18 Expected return on plan assets (198) (190) (199) (8) (7) (8) Amortization of prior service cost (benefit) 1 (1) 1 (9) (10) (9) Amortization of net loss 124 113 149 2 1 6 Net Periodic Benefit Cost 79 91 121 1 3 11 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Curtailments (18) — — — — — Net loss (gain) 46 80 175 11 13 (37) Amortization of net loss (124) (113) (149) (2) (1) (6) Current year prior service cost (credit) 7 (2) — — — (3) Amortization of prior service (cost) benefit (1) 1 (1) 9 10 9 Total Other Changes (90) (34) 25 18 22 (37) Total Recognized $ (11) $ 57 $ 146 $ 19 $ 25 $ (26) Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2020, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2020 2019 2018 2020 2019 2018 (Millions) Net Periodic Benefit Cost: Service cost $ 1 $ 1 $ — $ — $ — $ — Interest cost 1 2 2 — — 1 Expected return on plan assets (2) (2) (2) — — — Amortization of net loss (gain) 2 1 1 (1) (1) — Settlement charge 1 — 1 — — — Net Periodic Benefit Cost 3 2 2 (1) (1) 1 Other Changes in plan assets and benefit obligations recognized in OCI: Net loss (gain) 1 — 1 — — (3) Amortization of net (loss) gain (2) (1) (1) 1 1 — Amortization of prior service cost — — — — (2) — Total Other Changes (1) (1) — 1 (1) (3) Total Recognized $ 2 $ 1 $ 2 $ — $ (2) $ (2) The net periodic benefit cost for postretirement benefits represents the amount expensed for providing health care benefits to retirees and their eligible dependents. We include the service cost component in other operating expenses net of capitalized portion and include the components of net periodic benefit cost other than the service cost component in other expense. The weighted-average assumptions used to determine our benefit obligations as of December 31, 2020 and 2019 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2020 2019 2020 2019 Discount rate 2.34 % 3.01 % 2.19 % 2.99 % Rate of compensation increase 3.52 % 3.66 % 3.50 % 3.48 % Interest crediting rate 2.87 % 2.87 % N/A N/A The discount rate is the rate at which the benefit obligations could presently be effectively settled. We determined the discount rates by developing yield curves derived from a portfolio of high grade noncallable bonds with yields that closely match the duration of the expected cash flows of our benefit obligations. The weighted-average assumptions used to determine our net periodic benefit cost for the years ended December 31, 2020, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2020 2019 2018 2020 2019 2018 Discount rate 3.01 % 3.98 % 3.68 % 2.99 % 3.97 % 3.67 % Expected long-term return on plan assets 7.30 % 7.30 % 7.30 % 5.09 % 5.08 % 5.08 % Rate of compensation increase 3.66 % 3.79 % 3.85 % 3.48 % 3.50 % 3.50 % We developed our expected long-term rate of return on plan assets assumption based on a review of long-term historical returns for the major asset classes, the target asset allocations, and the effect of rebalancing of plan assets discussed below. Our analysis considered current capital market conditions and projected conditions. NYSEG, RG&E and UIL amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. Our other companies use the standard amortization methodology under which amounts in excess of ten-percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement. Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 Health care cost trend rate assumed for next year 5.25%/7.25% 6.75%/7.75% Rate to which cost trend rate is assumed to decline (ultimate trend rate) 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2029 / 2025 2029 / 2027 Contributions We make annual contributions in accordance with our funding policy of not less than the minimum amounts as required by applicable regulations. We expect to contribute $75 million and $17 million, respectively, to our pension and other postretirement benefit plans during 2021. Estimated Future Benefit Payments Expected benefit payments as of December 31, 2020 consisted of: (Millions) Pension Benefits Postretirement Benefits 2021 $ 211 $ 31 2022 $ 224 $ 30 2023 $ 217 $ 29 2024 $ 219 $ 29 2025 $ 474 $ 49 2026 - 2030 $ 765 $ 100 Non-Qualified Retirement Benefit Plans We also sponsor various unfunded pension plans for certain current employees, former employees and former directors. The total liability for these plans, which is included in Other current and Other non-current liabilities on our consolidated balance sheets, was $59 million and $56 million at December 31, 2020 and 2019, respectively. Plan Assets Our pension benefits plan assets are consolidated in one master trust. A consolidated trust provides for a uniform investment manager lineup and an efficient, cost effective means of allocating expenses and investment performance to each plan. Our primary investment objective is to ensure that current and future benefit obligations are adequately funded and with volatility commensurate with our risk tolerance. Preservation of capital and achievement of sufficient total return to fund accrued and future benefits obligations are of highest concern. Our primary means for achieving capital preservation is through diversification of the trusts’ investments while avoiding significant concentrations of risk in any one area of the securities markets. Further diversification is achieved within each asset group through utilizing multiple asset managers and systematic allocation to various asset classes and providing broad exposure to different segments of the equity, fixed income and alternative investment markets. The asset allocation policy is the most important consideration in achieving our objective of superior investment returns while minimizing risk. Networks and ARHI have established target asset allocation policies within allowable ranges for their pension benefits plan assets within broad categories of asset classes made up of Return-Seeking investments and Liability-Hedging investments. Networks currently has target allocations ranging from 35%-70% for Return-Seeking assets and 34%-65% for Liability-Hedging assets. ARHI currently has a target allocation of 60% for Return-Seeking assets and 40% for Liability-Hedging assets. Return-Seeking assets also include investments in real estate, global asset allocation strategies and hedge funds. Liability-Hedging investments generally consist of long-term corporate bonds, annuity contracts, long-term treasury STRIPS and opportunistic fixed income investments. Systematic rebalancing within the target ranges increases the probability that the annualized return on the investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges. The fair values of pension benefits plan assets, by asset category, as of December 31, 2020, consisted of: As of December 31, 2020 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 120 $ — $ 120 $ — U.S. government securities 177 177 — — Common stocks 107 107 — — Registered investment companies 301 301 — — Corporate bonds 710 — 710 — Preferred stocks 1 1 — — Common collective trusts 1,018 — 1,018 — Other, principally annuity, fixed income 50 6 44 — $ 2,484 $ 592 $ 1,892 $ — Other investments measured at net asset value 608 Total $ 3,092 The fair values of pension benefits plan assets, by asset category, as of December 31, 2019, consisted of: As of December 31, 2019 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 42 $ — $ 42 $ — U.S. government securities 87 87 — — Registered investment companies 464 464 — — Corporate bonds 458 — 458 — Preferred stocks 1 1 — — Common collective trusts 572 — 572 — Other, principally annuity, fixed income 84 — 84 — $ 1,708 $ 552 $ 1,156 $ — Other investments measured at net asset value 1,140 Total $ 2,848 Valuation Techniques We value our pension benefits plan assets as follows: • Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings. • U.S. government securities – at the closing price reported in the active market in which the security is traded. • Common stocks – at the closing price reported in the active market in which the individual investment is traded. • Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings. • Preferred stocks – at the closing price reported in the active market in which the individual investment is traded. • Common collective trusts/Registered investment companies – Level 1: at the closing price reported in the active market in which the individual investment is traded. Level 2 - the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market. • Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings. • Other investments measured at net asset value (NAV) – fund shares offered to a limited group of investors and alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient. Our postretirement benefits plan assets are held with trustees in multiple voluntary employees’ beneficiary association (VEBA) and 401(h) arrangements and are invested among and within various asset classes to achieve sufficient diversification in accordance with our risk tolerance. This is achieved for our postretirement benefits plan assets through the utilization of multiple institutional mutual and money market funds, providing exposure to different segments of the fixed income, equity and short-term cash markets. Approximately 37% of the postretirement benefits plan assets are invested in VEBA and 401(h) arrangements that are not subject to income taxes with the remainder being invested in arrangements subject to income taxes. Networks has established a target asset allocation policy within allowable ranges for postretirement benefits plan assets of 45%-65% for equity securities, 25%-45% for fixed income and 5%-25% for all other investment types. ARHI’s asset allocation policy has a target allocation of 45% in equity securities, 50% in fixed income and 5% for cash and cash equivalents investments. Equity investments are diversified across U.S. and non-U.S. stocks, investment styles, and market capitalization ranges. Fixed income investments are primarily invested in U.S. bonds and may also include some non-U.S. bonds. Other asset classes, including alternative investments, are used to enhance long-term returns while improving portfolio diversification. We primarily minimize the risk of large losses through diversification but also through monitoring and managing other aspects of risk through quarterly investment portfolio reviews. Systematic rebalancing within target ranges increases the probability that the annualized return on investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges. The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2020 consisted of: As of December 31, 2020 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 6 $ — $ 6 $ — U.S. government securities 1 1 — — Registered investment companies 141 141 — — Corporate bonds 3 — 3 — Common collective trusts 4 — 4 — Other, principally annuity, fixed income 9 — 9 — $ 164 $ 142 $ 22 $ — Other investments measured at net asset value 3 Total $ 167 The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2019 consisted of: As of December 31, 2019 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 31 $ — $ 31 $ — Common stocks 16 16 — — Registered investment companies 98 98 — — Corporate bonds 2 — 2 — Other, principally annuity, fixed income 8 — 8 — Total $ 155 $ 114 $ 41 $ — Valuation Techniques We value our postretirement benefits plan assets as follows: • Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings. • U.S. government securities – at the closing price reported in the active market in which the security is traded. • Common stocks and registered investment companies – at the closing price reported in the active market in which the individual investment is traded. • Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings. • Common collective trusts – the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market. • Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings. • Other investments measured at net asset value (NAV) – fund shares offered to a limited group of investors and alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient. Pension and postretirement benefit plan equity securities did not include any Iberdrola common stock as of both December 31, 2020 and 2019. Defined contribution plans We also have defined contribution plans defined as 401(k)s for all eligible AVANGRID employees. There are various match formulas depending on years of service, age and pension plan closure/freeze date. For the years ended December 31, 2020, 2019 and 2018, the annual contributions we made to these plans was $49 million, $40 million and $37 million, respectively.

Equity

Equity	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Equity	Equity As of December 31, 2020 and 2019, we had 413,782 and 485,810 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2020 and 2019, we issued 42,777 and 0 shares of common stock, respectively, and released 72,028 and 0 shares of common stock held in trust, respectively, each having a par value of $0.01. During January 2021, we released 292,594 shares of common stock held in trust. We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain Iberdrola's relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In May 2020, 42,777 shares were repurchased pursuant to the stock repurchase program. As of December 31, 2020, a total of 303,835 shares have been repurchased in the open market, all of which are included as AVANGRID treasury shares. As of December 31, 2020, the total cost of all repurchases, including commissions, was $14 million. Accumulated OCI (Loss) Accumulated OCI (Loss) for the years ended December 31, 2020, 2019 and 2018 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2017 Adoption of new accounting standard 2018 Change As of December 31, 2018 Adoption of new accounting standard 2019 Change As of December 31, 2019 2020 Change As of December 31, 2020 (Millions) Change in revaluation of defined benefit plans, net of income tax expense (benefit) of $1 for 2018, $0 for 2019 and $0 for 2020 $ (14) $ — $ 3 $ (11) $ (2) $ 1 $ (12) $ — $ (12) Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) of $0 for 2018, $(1) for 2019 and $3 for 2020 (6) (1) 1 (6) — (1) (7) (13) (20) Unrealized (loss) gain on derivatives qualifying as cash flow hedges: Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $(7) for 2018, $(9) for 2019 and $(7) for 2020 30 — (21) 9 — (22) (13) (22) (35) Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $(7) for 2018, $3 for 2019 and $2 for 2020 (a) (56) — (8) (64) (10) 11 (63) 19 (44) Loss on derivatives qualifying as cash flow hedges (26) — (29) (55) (10) (11) (76) (3) (79) Accumulated Other Comprehensive Loss $ (46) $ (1) $ (25) $ (72) $ (12) $ (11) $ (95) $ (16) $ (111) (a) Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2020, 2019 and 2018, respectively, consisted of: Years Ended December 31, 2020 2019 2018 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 581 $ 667 $ 587 Denominator: Weighted average number of shares outstanding - basic 309,494,939 309,491,082 309,503,319 Weighted average number of shares outstanding - diluted 309,559,387 309,514,910 309,712,628 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 1.88 $ 2.16 $ 1.90 Earnings Per Common Share, Diluted $ 1.88 $ 2.16 $ 1.89

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entities	Variable Interest Entities We participate in certain partnership arrangements that qualify as 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 consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs. On March 2, 2020, we closed on two TEF agreements, receiving $237 million from two tax equity investors related to two wind farms that reached commercial operation. On May 8, 2020, we closed on a TEF agreement, receiving $70 million from the same tax equity investors related to a wind farm that reached commercial operation. The three wind farms are part of a portfolio of companies called Aeolus Wind Power VII, LLC (Aeolus VII). On February 5, 2021, we closed on the final TEF agreement for Aeolus VII in a non-cash transaction. The four Aeolus VII wind farms total 688 MW of wind power. As of December 31, 2020, the assets and liabilities of the VIEs totaled approximately $1,713 million and $107 million, respectively. As of December 31, 2019, the assets and liabilities of VIEs totaled approximately $806 million and $29 million, respectively. At both December 31, 2020 and 2019, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment. 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. At December 31, 2020, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot) and Aeolus VII are our consolidated VIEs. 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 22 - Equity Method Investments for information on our VIE we do not consolidate.

Grants, Government Incentives a

Grants, Government Incentives and Deferred Income	12 Months Ended
	Dec. 31, 2020
Other Liabilities Disclosure [Abstract]
Grants, Government Incentives and Deferred Income	Grants, Government Incentives and Deferred Income The changes in deferred income as of December 31, 2020 and 2019 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2018 $ 1,367 $ 18 $ 1,385 Disposals (3) — (3) Derecognition due to sale (a) (38) — (38) Recognized in income (68) (2) (70) As of December 31, 2019 1,258 16 1,274 Disposals (2) — (2) Recognized in income (66) (2) (68) As of December 31, 2020 $ 1,190 $ 14 $ 1,204 (a) Grants no longer controlled by us due to the 2019 sale of a 50% interest in the Poseidon projects. See Note 22 for further information. Within deferred income, we classify grants we received under Section 1603 of the American Recovery and Reinvestment Act of 2009, where the United States Department of Treasury (DOT) provides eligible parties the option of claiming grants for specified energy property in lieu of tax credits, which we claimed for the majority of our qualifying properties. Deferred income has been recorded for the grant amounts and is amortized as an offset against depreciation expense using the straight-line method over the estimated useful life of the associated property to which the grants apply. We recognize a net deferred tax asset for the book to tax basis differences related to the property for income tax purposes within the nontaxable grant revenue deferred income tax liabilities (see Note 16 – Income Taxes). We are required to comply with certain terms and conditions applicable to each grant and, if a disqualifying event should occur as specified in the grant’s terms and conditions, we are required to repay the grant funds to the DOT. We believe we are in compliance with each grant’s terms and conditions as of December 31, 2020 and 2019.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2020
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investment	Equity Method Investments On December 16, 2020, Renewables sold an 85% ownership interest in a wind farm located in South Dakota (Tatanka) to WEC Infrastructure involving total consideration of $238 million, excluding closing costs, and recognized a gain of $12 million, net of tax. The pre-tax gain of $16 million is included in "Other income (expense)" in our consolidated statements of income. Our retained investment in Tatanka of $24 million was valued based on an enterprise value of $298 million and applying an effective percentage of economic benefits retained of 7.97%, which was derived from a DCF model similar to the model used for Goodwill as described in Note 7. The net gain includes $4 million related to the remeasurement of our retained investment in Tatanka. The transaction was accounted for as a sale of assets and resulted in a loss of control. The retained 15% ownership interest is accounted for as an equity method investment. As of December 31, 2020, the carrying value of our Tatanka investment was $24 million. On December 13, 2019, Renewables transferred a 50% ownership interest in a wind farm and a solar project located in Arizona (Poseidon) to Axium involving total consideration of $112 million, excluding closing costs, and recognized a gain of $96 million, net of tax. The pre-tax gain of $134 million is included in "Other income (expense)" in our consolidated statements of income. The net gain includes $50 million related to the remeasurement of our retained investment in Poseidon which was valued based on the consideration received in the transaction. The transaction was accounted for as the sale of a business and resulted in a loss of control. The retained 50% ownership interest is accounted for as an equity method investment. As of December 31, 2020 and 2019, the carrying value of our Poseidon investment was $104 million and $111 million, respectively. In December 2018, Renewables sold 80% of our wholly owned subsidiary, Coyote Ridge Wind, LLC (Coyote Ridge), including substantially all of the related tax benefits, to WEC Infrastructure in exchange for $144 million of total proceeds with $84 million received in 2019 to complete the transaction. We recorded a gain of $4 million and $10 million from this transaction in “Other expense" in our consolidated statements of income for the years ended December 31, 2019 and 2018, respectively. We account for the remaining 20% membership interest under the equity method of accounting. As of December 31, 2020 and 2019, the carrying amount of our Coyote Ridge investment was $16 million and $14 million, respectively. Renewables has two 50-50 joint ventures with Horizon Wind Energy, LLC, which own and operate the Flat Rock Windpower LLC (Flat Rock I) and the Flat Rock Wind Power II LLC (Flat Rock II) wind farms located in upstate New York. Flat Rock I has a 231 MW capacity and Flat Rock II has a 91 MW capacity. We account for the Flat Rock joint ventures under the equity method of accounting. As of December 31, 2020 and 2019, the carrying amount of Flat Rock I was $98 million and $105 million, respectively, and Flat Rock II was $47 million and $49 million, respectively. 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. Pursuant to a joint bidding agreement between Renewables and CIP, CIP held a right to sell all or a portion of its 50% ownership interest to Renewables, subject to certain conditions, which expired on September 30, 2020. During 2019, 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 December 31, 2020, under the provisions of the LLC agreement, Renewables has contributed $252 million to Vineyard Wind, net of reimbursement by CIP. We expect to provide additional capital contributions. In October 2020, Vineyard Wind submitted an offshore wind solicitation to NYSERDA. Renewables and CIP entered into a joint bidding agreement pursuant to which, subject to the satisfaction of certain conditions, CIP may exercise an option to effectuate a series of transactions that include the sale of its ownership interest in the Liberty Wind and Park City Wind Projects to Renewables and the purchase of Renewables’ residual ownership interest in certain lease areas that have not been awarded an offtake agreement as of the date of the exercise of such option by CIP. On January 14, 2021, the options held by CIP related to Liberty Wind expired as the project was not selected by NYSERDA. 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 December 31, 2020 and 2019, the carrying amount of Renewables' investment in Vineyard Wind was $245 million and $227 million, respectively. Networks is a party to a 50-50 joint venture with Clearway Energy, Inc. in GenConn, which operates two peaking generation plants in Connecticut. The investment in GenConn is accounted for as an equity investment. As of December 31, 2020 and 2019, the carrying value of our GenConn investment was $104 million and $113 million, respectively. Networks holds an approximate 20% ownership interest in New York TransCo. Through New York TransCo, Networks has formed a partnership with Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, which is a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York. On April 8, 2019, New York Transco was selected as the developer for Segment B of the AC Transmission Public Policy Project by the NYISO. The selected project, New York Energy Solution (NYES), replaces nearly 80-year old transmission assets located in the upper to mid-Hudson Valley with streamlined, modernized technology, to enable surplus clean energy resources in upstate New York and help achieve the State’s energy goals. The total project cost is $600 million plus interconnection costs. NYSEG’s contribution as 20% co-owner is $120 million. New York Transco is subject to regulatory approval of its rates, terms and conditions with the FERC. As of December 31, 2020 and 2019, the amount receivable from New York TransCo was $0 and $1 million, respectively. The investment in New York TransCo is accounted for as an equity investment. As of December 31, 2020 and 2019, the carrying value of our New York TransCo investment was $30 million and $26 million, respectively. None of our joint ventures have any contingent liabilities or capital commitments. Distributions received from equity method investments amounted to $22 million, $17 million and $18 million for the years ended December 31, 2020, 2019 and 2018 respectively, which are reflected as either distributions of earnings or as returns of capital in the operating and investing sections of the consolidated statements of cash flows, respectively. In addition, during the years ended December 31, 2020 and 2019, we received $14 million and $9 million of distributions in RECs from our equity method investments. As of December 31, 2020, there was an immaterial amount of undistributed earnings from our equity method investments. Capitalized interest costs related to equity method investments were $8 million and $7 million for the years ended December 31, 2020 and 2019, respectively.

Other Financial Statements Item

Other Financial Statements Items	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Other Financial Statements Items	Other Financial Statements Items Loss from assets held for sale In connection with the 2018 sale of our gas trading and storage businesses, we recorded a loss from held for sale measurement of $16 million for the year ended December 31, 2018, which is included in “Loss from assets held for sale” in our consolidated statements of income. Other income (expense) Other income (expense) for the years ended December 31, 2020, 2019 and 2018 consisted of: Years ended December 31, 2020 2019 2018 (Millions) Gain on sale of assets (a) $ 20 $ 148 $ 10 Allowance for funds used during construction 56 46 30 Carrying costs on regulatory assets 28 21 21 Non-service component of net periodic benefit cost (62) (79) (128) Other (24) (15) 1 Total Other Income (Expense) $ 18 $ 121 $ (66) (a) 2020 includes a $16 million gain from the Tatanka sale, 2019 includes a $134 million gain from the Poseidon sale and 2018 includes a $10 million gain from the Coyote Ridge sale (see Note 22). Accounts receivable and unbilled revenues, net Accounts receivable and unbilled revenues, net as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Trade receivables and unbilled revenues $ 1,295 $ 1,151 Allowance for credit losses (108) (69) Total Accounts receivable and unbilled revenues, net $ 1,187 $ 1,082 The change in the allowance for credit losses as of December 31, 2020 and 2019 consisted of: (Millions) As of December 31, 2017 $ 64 Current period provision 74 Write-off as uncollectible (76) As of December 31, 2018 $ 62 Current period provision 92 Write-off as uncollectible (85) As of December 31, 2019 $ 69 Current period provision 83 Write-off as uncollectible (44) As of December 31, 2020 $ 108 DPA receivable balances were $78 million and $65 million as of December 31, 2020 and 2019, respectively. Prepayments and Other Current Assets Prepayments and other current assets as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Prepaid other taxes $ 135 $ 123 Short-term investment (a) 300 — Broker margin and collateral accounts 30 33 Other pledged deposits 2 3 Prepaid expenses 41 34 Other 17 6 Total $ 525 $ 199 (a) Short-term investment from proceeds of the Iberdrola Loan. Other current liabilities Other current liabilities as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Advances received $ 141 $ 143 Accrued salaries 109 89 Short-term environmental provisions 49 40 Collateral deposits received 42 44 Pension and other postretirement 5 5 Finance leases 8 9 Other 14 6 Total $ 368 $ 336

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Segment Information	Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments: • Networks: includes all of the energy transmission and distribution activities, any other regulated activity originating in New York and Maine and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes eight rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment. • Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities. The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude restructuring charges, mark-to-market earnings from changes in the fair value of derivative instruments, loss from held for sale measurement, accelerated depreciation derived from repowering of wind farms, impact of the Tax Act, costs incurred related to the PNMR Merger, costs incurred in connection with the COVID-19 pandemic and adjustments for the non-core Gas storage business. Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in our consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment. The segment information as of and for the years ended December 31, 2019 and 2018 has been revised consistent with the immaterial corrections to prior periods disclosed in Note 2, including a correction of $24 million of income tax expense at the Renewables segment for the year ended December 31, 2019 from the as reported amount of $4 million. Segment information as of and for the year ended December 31, 2020 consisted of: For the year ended December 31, 2020 Networks Renewables Other(a) AVANGRID Consolidated (Millions) Revenue - external $ 5,187 $ 1,132 $ 1 $ 6,320 Revenue - intersegment 1 — (1) — Depreciation and amortization 592 394 1 987 Operating income 877 (16) 8 869 Earnings (losses) from equity method investments 10 (13) — (3) Interest expense, net of capitalization 234 7 75 316 Income tax expense (benefit) 120 (80) (11) 29 Capital expenditures 1,838 943 — 2,781 Adjusted net income 568 115 (58) 625 As of December 31, 2020 Property, plant and equipment 17,079 9,662 10 26,751 Equity method investments 134 534 — 668 Total assets $ 24,592 $ 12,867 $ 364 $ 37,823 (a) Includes Corporate and intersegment eliminations. Segment information as of and for the year ended December 31, 2019 consisted of: For the year ended December 31, 2019 Networks Renewables Other(a) AVANGRID Consolidated (Millions) Revenue - external $ 5,150 $ 1,184 $ 2 $ 6,336 Revenue - intersegment 14 — (14) — Depreciation and amortization 549 383 1 933 Operating income 890 93 15 998 Earnings (losses) from equity method investments 11 (8) — 3 Interest expense, net of capitalization 269 14 27 310 Income tax expense (benefit) 152 28 (11) 169 Capital expenditures 1,610 1,122 3 2,735 Adjusted net income 465 193 (17) 640 As of December 31, 2019 Property, plant and equipment 15,829 9,357 10 25,196 Equity method investments 139 506 — 645 Total assets $ 23,239 $ 13,152 $ (1,997) $ 34,394 (a) Includes Corporate and intersegment eliminations. Segment information for the year ended December 31, 2018 consisted of: For the year ended December 31, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 5,304 $ 1,136 $ 37 $ 6,477 Revenue - intersegment 6 2 (8) — Loss from assets held for sale — — 16 16 Depreciation and amortization 503 352 — 855 Operating income 968 132 16 1,116 Earnings (losses) from equity method investments 13 (3) — 10 Interest expense, net of capitalization 260 33 10 303 Income tax expense (benefit) 167 (32) 32 167 Capital expenditures 1,370 407 — 1,777 Adjusted net income $ 481 $ 182 $ 13 $ 676 (a) Includes Corporate, Gas and intersegment eliminations. Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the years ended December 31, 2020, 2019 and 2018 is as follows: Years Ended December 31, 2020 2019 2018 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 625 $ 640 $ 676 Adjustments: Restructuring charges (1) (6) (6) (4) Mark-to-market adjustments - Renewables (2) (5) 76 (25) Loss from held for sale measurement (3) — — (16) Impact of the Tax Act (4) — — (46) Accelerated depreciation from repowering (5) (9) (33) (3) Impact of COVID-19 (6) (29) — — Merger costs (7) (6) — — Legal settlement - Gas storage (8) (5) — — Income tax impact of adjustments 16 (10) (6) Gas Storage, net of tax (8) — — 11 Net Income Attributable to Avangrid, Inc. $ 581 $ 667 $ 587 (1) Restructuring and severance related charges relate to costs resulted from restructuring actions involving initial targeted voluntary workforce reductions and related costs in our plan to vacate a lease, predominantly within the Networks segment and costs to implement an initiative to mitigate costs and achieve sustainable growth (See Note 27 - Restructuring and Severance Related Expenses – for further details). (2) Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas. (3) Represents loss from measurement of assets and liabilities held for sale in connection with the committed plan to sell the gas trading and storage businesses. (4) Represents the impact from measurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. (5) Represents the amount of accelerated depreciation derived from repowering wind farms in Renewables. (6) Represents costs incurred in connection with the COVID-19 pandemic. (7) Pre-merger costs incurred. (8) Removal of the impact from Gas activity in the reconciliation to AVANGRID Net Income.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Related Party Transactions	Related Party TransactionsWe engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the years ended December 31, 2020, 2019 and 2018, respectively, consisted of: Years Ended December 31, 2020 2019 2018 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ 1 $ (43) $ 1 $ (42) $ 1 $ (38) Iberdrola Renovables Energia, S.L. $ — $ (9) $ — $ (9) $ — $ (14) Iberdrola Financiación, S.A. $ — $ (7) $ — $ (3) $ — $ (3) Vineyard Wind $ 9 $ — $ 13 $ — $ 3 $ — Iberdrola Solutions $ 2 $ — $ 1 $ — $ — $ — Iberdrola Energia Monterrey, S.A. de C.V. $ — $ — $ — $ — $ 3 $ — Iberdrola Canada Energy Services, Ltd $ — $ — $ — $ — $ — $ (5) Other $ — $ — $ 1 $ (3) $ 2 $ (5) In addition to the statements of income items above, we made purchases of turbines for wind farms from Siemens-Gamesa, in which Iberdrola had an 8.1% ownership interest until Iberdrola sold its interest in February 2020. After the sale, the turbine purchases are no longer considered related party transactions. The amounts capitalized for transactions while Siemens-Gamesa was considered a related party were $11 million and $18 million for the years ended December 31, 2020 and 2019, respectively. Related party balances as of December 31, 2020 and 2019, respectively, consisted of: As of December 31, 2020 2019 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ 2 $ (43) $ 1 $ (42) Iberdrola Financiacion $ — $ (6) $ — $ (3) Siemens-Gamesa (a) $ — $ — $ — $ (18) Vineyard Wind $ 4 $ — $ 5 $ — Iberdrola Solutions $ 5 $ — $ — $ — Other $ 1 $ (1) $ 4 $ (1) (a) After Iberdrola's sale of its interest of Siemens-Gamesa in February 2020, transactions with Siemens-Gamesa are no longer considered related party. Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. See Note 10 for a discussion of the Iberdrola Loan. 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 December 31, 2020 and 2019 was $0 and $150 million, respectively. AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of both December 31, 2020 and 2019, there were no amounts outstanding under this credit facility. We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had a notes receivable balance of $5 million and $0 for the years ended December 31, 2020 and 2019, respectively. Renewables has financial forward power contracts with Iberdrola Solutions to hedge Renewables merchant wind exposure in Texas. See Note 22 - Equity Method Investments for information on transactions with our equity method investees. 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.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Stock-Based Compensation	Stock-Based Compensation 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). As of December 31, 2020, the total number of shares authorized for stock-based compensation plans was 2,500,000. Performance Stock Units During 2016, 1,298,683 performance stock units (PSUs) were granted to certain officers and employees of AVANGRID. In 2017, 2018 and 2019, an additional 85,759, 75,350 and 3,881 PSUs, respectively, were granted to officers and employees of AVANGRID under the Plan with achievement measured based on certain performance and market-based metrics for the 2016 to 2019 time period. The fair value of the PSUs on the grant date was $31.80 per share, which is expensed on a straight-line basis over the requisite service period of approximately seven years based on expected achievement. 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 recent quarterly dividend payment and the stock price as of the grant date. In February 2020, a total number of 208,268 PSUs, before applicable taxes, were approved as earned by participants based on achievement of certain performance metrics related to the 2016 through 2019 plan and are payable in three equal installments, net of applicable taxes, in 2020, 2021 and 2022. The remaining unvested PSUs were forfeited. In May 2020, 42,777 shares of common stock were issued to settle the first installment payment and 2,605 PSUs were forfeited from the originally approved total number of PSUs. Restricted Stock Units In June and October 2018, pursuant to the Avangrid, Inc. Omnibus Incentive Plan two restricted stock units (RSUs) awards of 60,000 and 8,000 RSUs, respectively, were granted to certain officers of AVANGRID. The RSUs vest in full in one installment in June and December 2020, respectively for each award, provided that the grantee remains continuously employed with AVANGRID through the applicable date. The fair value on the grant date was determined based on a price of $50.40 per share for the June 2018 awards and $47.59 per share for the October 2018 awards. In June 2020, 60,000 RSU's, plus dividend equivalents accrued through the vesting period, were settled for $3 million in cash. In August 2020, 5,000 RSUs were granted to an officer of AVANGRID. The RSUs vest in three equal installments in 2021, 2022 and 2023, provided that the grantee remains continuously employed with AVANGRID through the applicable vesting dates. The fair value on the grant date was determined based on a price of $48.99 per share. Phantom Share Units On March 18, 2020, 167,060 Phantom Shares were granted to certain AVANGRID executives and employees. These awards will vest in three equal installments in 2020, 2021 and 2022 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of AVANGRID’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of AVANGRID’s common stock at each reporting date until the date of settlement. In June 2020, $2 million was paid to settle the first installment under this plan. As of December 31, 2020, the total liability is $2 million, which is included in other current and non-current liabilities. The total stock-based compensation expense, which is included in "Operations and maintenance" of our consolidated statements of income for the years ended December 31, 2020, 2019 and 2018 was $14 million, $3 million and $2 million, respectively. The total income tax benefits recognized for stock-based compensation arrangements for each of the years ended December 31, 2020, 2019 and 2018, were $4 million, $1 million and $1 million, respectively. A summary of the status of the AVANGRID's nonvested PSUs and RSUs as of December 31, 2020, and changes during the fiscal year ended December 31, 2020, is presented below: Number of PSUs and RSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2019 1,274,280 $ 32.83 Granted 6,691 $ 49.20 Forfeited (997,088) $ 31.80 Vested (141,716) $ 41.44 Nonvested Balance – December 31, 2020 142,167 $ 32.42 As of December 31, 2020, total unrecognized costs for non-vested PSUs, RSUs and Phantom Shares was $3 million. The weighted-average period over which the PSU, RSU and Phantom Shares costs will be recognized is approximately 2 years. The weighted-average grant date fair value of RSUs granted during the year was $49.20 per share for the year ended December 31, 2020.

Restructuring and Severance Rel

Restructuring and Severance Related Expenses	12 Months Ended
	Dec. 31, 2020
Restructuring and Related Activities [Abstract]
Restructuring and Severance Related Expenses	Restructuring and Severance Related Expenses In 2017, we announced initial targeted voluntary workforce reductions predominantly within the Networks segment. Those actions primarily included: reducing our workforce through voluntary programs in various areas to better align our people resources with business demands and priorities; reorganizing our human resources function to substantially consolidate in Connecticut, as well as related costs to vacate a lease and relocate employees; and reducing our information technology workforce to make increasing use of external services for operations, support and development of systems. In 2019, we announced changes across the Company aimed to mitigate costs and deliver sustainable growth, including outsourcing and insourcing of certain areas of the Company and technology initiatives that help improve efficiency and reduce costs. For the years ended December 31, 2020, 2019 and 2018, those decisions and transactions resulted in restructuring charges of $2 million, $4 million and $3 million, respectively, for severance expenses, which are included in “Operations and maintenance” in the consolidated statements of income. "Depreciation and amortization" in our consolidated statements of income includes $4 million and $2 million, respectively, for the years ended December 31, 2020 and 2019 for restructuring activities. For the year ended December 31, 2020, the severance and lease restructuring charges reserves, which are recorded in “Other current liabilities” and “Other liabilities”, consisted of: For the Year Ended December 31, 2020 (Millions) Beginning Balance $ 5 Restructuring and severance related expenses 2 Payments (4) Ending Balance $ 3

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent events	Subsequent events 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. We cannot predict the outcome of this matter. On February 15, 2021, 1,181,031 PSUs were granted to certain officers and employees of AVANGRID pursuant to the Plan with achievement measured based on certain performance and market-based metrics for the 2021 to 2022 performance period. The PSUs will payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. On February 16, 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 April 1, 2021 to shareholders of record at the close of business on March 5, 2021.

CONDENSED FINANCIAL INFORMATION

CONDENSED FINANCIAL INFORMATION OF PARENT	12 Months Ended
	Dec. 31, 2020
Condensed Financial Information Disclosure [Abstract]
CONDENSED FINANCIAL INFORMATION OF PARENT	Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF INCOME FOR THE YEARS ENDED December 31, 2020, 2019 AND 2018 Years Ended December 31, 2020 2019 2018 (Millions) Operating Revenues $ — $ — $ — Operating Expenses Operating expense 10 3 3 Taxes other than income taxes (11) (12) (11) Total Operating Expenses (1) (9) (8) Operating Income 1 9 8 Other Income Other income 35 59 48 Equity earnings of subsidiaries 641 678 596 Interest expense (109) (93) (56) Income Before Income Tax 568 653 596 Income tax (benefit) expense (13) (14) 9 Net Income $ 581 $ 667 $ 587 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED December 31, 2020, 2019, AND 2018 Years Ended December 31, 2020 2019 2018 (Millions) Net Income $ 581 $ 667 $ 587 Other comprehensive loss of subsidiaries (16) (11) (25) Comprehensive Income $ 565 $ 656 $ 562 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT BALANCE SHEETS AS OF December 31, 2020 AND 2019 As of December 31, 2020 2019 (Millions) Assets Current Assets Cash and cash equivalents $ 1,438 $ 146 Accounts receivable from subsidiaries 124 22 Notes receivable from subsidiaries 1,489 2,529 Prepayments and other current assets 357 — Total current assets 3,408 2,697 Investments in subsidiaries 18,356 16,812 Other assets Deferred income taxes 388 374 Other 3 3 Total other assets 391 377 Total Assets $ 22,155 $ 19,886 Liabilities Current Liabilities Current portion of debt $ — $ 456 Notes payable 308 561 Notes payable to subsidiaries 1,375 1,674 Accounts payable and accrued liabilities 12 2 Accounts payable to subsidiaries 9 7 Interest accrued 9 10 Interest accrued subsidiaries 10 18 Dividends payable 136 136 Taxes accrued — 24 Total current liabilities 1,859 2,888 Non-current debt 2,087 1,808 Non-current debt with affiliate 3,000 — Total Liabilities 6,946 4,696 Equity Stockholders' Equity: Common stock 3 3 Additional paid-in capital 13,665 13,660 Treasury stock (14) (12) Retained earnings 1,666 1,634 Accumulated other comprehensive loss (111) (95) Total Equity 15,209 15,190 Total Liabilities and Equity $ 22,155 $ 19,886 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED December 31, 2020, 2019, AND 2018 Years Ended December 31, 2020 2019 2018 (Millions) Net Cash used in Operating Activities $ (142) $ (1,299) $ (323) Cash Flow from Investing Activities Notes receivable from subsidiaries (73) 633 462 Investments in subsidiaries (591) (399) (48) Return of capital from investments in subsidiaries 419 433 116 Other investments (300) — — Net Cash (used in) provided by Investing Activities (545) 667 530 Cash Flow from Financing Activities (Repayments) receipts of short-term notes payable from subsidiaries, net (14) 107 246 (Repayments) receipts of short-term notes payable (253) (27) 82 Proceeds from non-current debt 744 1,243 — Proceeds from non-current debt with affiliate 3,000 — — Repayments of non-current debt (950) — — Repurchase of common stock (2) — (4) Issuance of common stock (1) — (2) Dividends paid (545) (545) (537) Net Cash provided by (used in) Financing Activities 1,979 778 (215) Net Increase (Decrease) in Cash and Cash Equivalents 1,292 146 (8) Cash and Cash Equivalents, Beginning of Year 146 — 8 Cash and Cash Equivalents, End of Year $ 1,438 $ 146 $ — Supplemental Cash Flow Information Cash paid for interest $ 111 $ 85 $ 55 Cash paid (refunded) payment for income taxes $ 65 $ 43 $ 55 See accompanying notes to Schedule I. Avangrid, Inc. (AVANGRID) is a holding company and we conduct substantially all of our business through our subsidiaries. Substantially all of our consolidated assets are held by our subsidiaries. Accordingly, our cash flow and ability to meet our obligations are largely dependent upon the earnings of our subsidiaries and the distribution or other payment of their earnings to us in the form of dividends, loans or advances or repayment of loans and advances from us. Our condensed financial statements and related footnotes have been prepared in accordance with regulatory statute 210.12-04 of Regulation S-X. Our condensed financial statements should be read in conjunction with the consolidated financial statements and notes thereto of AVANGRID and subsidiaries (AVANGRID Group). AVANGRID indirectly or directly owns all of the ownership interests of our significant subsidiaries. AVANGRID relies on dividends or loans from our subsidiaries to fund dividends to our primary shareholder. AVANGRID’s significant accounting policies are consistent with those of the AVANGRID Group. For the purposes of these condensed financial statements, AVANGRID’s wholly owned and majority owned subsidiaries are recorded based upon our proportionate share of the subsidiaries net assets. AVANGRID will file a consolidated federal income tax return that includes the taxable income or loss of all our subsidiaries for the 2020 tax period. Each subsidiary company is treated as a member of the consolidated group and determines its current and deferred taxes separately and settles its current tax liability or benefit each year directly with AVANGRID pursuant to a tax sharing agreement between AVANGRID and our members. Immaterial Corrections to Prior Periods Our subsidiaries have identified various immaterial corrections primarily related to property, plant and equipment and deferred tax liabilities that originated in prior periods. AVANGRID determined that the cumulative impact of the corrections was not material to the results of operations, financial position or cash flows in previously issued financial statements and therefore, amendments of previously filed condensed financial information of AVANGRID are not required. However, we have revised the prior periods included within these financial statements to reflect these immaterial corrections. The corrections resulted in decreases of $33 million and $8 million in equity earnings and net income in the statements of income for the years ended December 31, 2019 and 2018, respectively, and a $47 million decrease in retained earnings and investments in subsidiaries in the balance sheet as of December 31, 2019. The revision decreased retained earnings by $6 million as of December 31, 2018. The revision had no net impact on the net cash provided by operating activities for the years ended December 31, 2019 and 2018. 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 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. 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, S.A. has provided AVANGRID a commitment letter (Iberdrola Funding Commitment Letter), pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration. To the extent AVANGRID wishes to effect a funding transaction under the Iberdrola Funding Commitment Letter in order to pay the Merger Consideration, the specific terms of any such transaction will be negotiated between Iberdrola and AVANGRID on an arm’s length basis and must be approved by both (i) a majority of the members of the unaffiliated committee of the board of directors of AVANGRID, and (ii) a majority of the board of directors of AVANGRID. Under the terms of such commitment letter, Iberdrola S.A. has agreed to negotiate with AVANGRID the specific terms of any transaction effecting such funding commitment promptly and in good faith, with the objective that such terms shall be commercially reasonable and approved by AVANGRID. AVANGRID’s and Merger Sub’s obligations under the Merger Agreement are not conditioned upon AVANGRID obtaining financing. The Merger Agreement provides for certain customary termination rights including the right of either party to terminate the Merger Agreement if the Merger is not completed on or before January 20, 2022 (subject to a three-month extension by either party if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been As of December 31, 2020, AVANGRID share capital consisted of 500,000,000 shares of common stock authorized, 309,794,917 shares issued and 309,077,300 shares outstanding, 81.5% of which are owned by Iberdrola, each having a par value of $0.01, for a total value of common stock of $3 million and additional paid in capital of $13,665 million. As of December 31, 2019, AVANGRID share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,272 shares outstanding, 81.5% of which were owned by Iberdrola, each having a par value of $ $0.01, for a total value of common stock capital of $3 million and additional paid in of $13,660 million. As of December 31, 2020 and 2019, we had 413,782 and 485,810 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2020 and 2019, we issued 42,777 and 0 shares of common stock, respectively, and released 72,028 and 0 shares of common stock held in trust, respectively, each having a par value of $0.01. During January 2021, we released 292,594 shares of common stock held in trust. We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain Iberdrola's relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In May 2020, 42,777 shares were repurchased pursuant to the stock repurchase program. As of December 31, 2020, a total of 303,835 shares have been repurchased in the open market, all of which are included as AVANGRID treasury shares. As of December 31, 2020, the total cost of all repurchases, including commissions, was $14 million. On February 16, 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 April 1, 2021 to shareholders of record at the close of business on March 5, 2021. In 2017, AVANGRID issued $600 million aggregate principal amount of its 3.15% notes maturing in 2024. On May 16, 2019, AVANGRID issued $750 million aggregate principal amount of its 3.80% notes maturing in 2029. Proceeds of the offering were used to finance and/or refinance, in whole or in part, one or more eligible renewable energy generation facilities. Net proceeds of the offering after the price discount and issuance-related expenses were $743 million. On April 9, 2020, AGR issued $750 million aggregate principal amount of unsecured notes maturing in 2025 at a fixed interest rate of 3.20%. Net proceeds of the offering after the price discount and issuance-related expenses were $744 million. Iberdrola Loan On December 14, 2020, AVANGRID entered into an intra-group loan agreement with Iberdrola 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 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 December 31, 2020, the Iberdrola Loan had no current maturities and is included in "Non-current debt with affiliate" on our condensed balance sheet as we do not intend on repaying the Iberdrola Loan with current assets. Proceeds from the Iberdrola Loan of $1,438 million and $300 million, respectively, are included in "cash and cash equivalents" and "prepayments and other current assets" on our condensed balance sheet as of December 31, 2020. The remainder of the proceeds reduced our commercial paper balance. Cash dividends paid by subsidiary are as follows: Years ended December 31, 2020 2019 2018 (millions) AVANGRID Networks $ 419 $ 433 $ 116 For the years ended December 31, 2020, 2019 and 2018, AVANGRID made capital contributions to Networks of $590 million, $158 million and $50 million, respectively. During 2020 and 2019, AVANGRID recorded a net non-cash contribution and dividend of $423 million and $219 million, respectively, to and from its subsidiaries to zero out their account balances of notes receivable and payable.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Principles of consolidation	Principles of consolidationWe consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. We account for investments in common stock where we have the ability to exercise significant influence, but not control, using the equity method of accounting.
Revenue recognition	Revenue recognitionWe recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. 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 24. 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. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to Federal Energy Regulatory Commission (FERC) regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO), or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer. The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service. We record revenue for all of such sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less. For its New York and Connecticut utilities, Networks assesses its DPAs at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result. Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms, other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues. 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 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. There are no material initial incremental costs of obtaining a contract or significant financing elements in any of the arrangements. 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. Certain customers may receive cash credits, which we account for as variable consideration. Renewables estimates those amounts based on the expected amount to be provided to customers and reduces revenues recognized. We believe that there will not be significant changes to our estimates of variable consideration. Other Other, which does not represent a segment, derives its revenues primarily from miscellaneous Corporate revenues including intersegment eliminations, and in 2018 also had revenues from providing natural gas storage services to customers, gas trading operations generally classified as derivative revenue in accordance with the applicable accounting standards and gas trading contracts not classified as derivatives. Contract Costs, Contract Liabilities and Practical Expedient 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 and $12 million at December 31, 2020 and 2019, respectively, and are presented in "Other non-current assets" on our 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 $9 million and $10 million at December 31, 2020 and 2019, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. For both the years ended December 31, 2020 and 2019, we recognized $21 million as revenue related to contract liabilities and for the year ended December 31, 2018, we recognized $13 million. We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.
Regulatory accounting	Regulatory accounting We account for our regulated utilities' operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by an independent, third-party regulator; (ii) rates are designed to recover the entity’s specific costs of providing the regulated services or products and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and can be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. We amortize regulatory assets and liabilities and recognize the related expense or revenue in our consolidated statements of income consistent with the recovery or refund included in customer rates. We believe it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates.
Business combinations and assets acquisitions	Business combinations and assets acquisitions (disposals) We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred, including contingent consideration, and the equity interests issued by the acquirer. We measure identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination initially at their fair values at the acquisition date. We record as goodwill the excess of the consideration transferred over the fair value of the identifiable net assets acquired. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. For business combinations, we expense acquisition-related costs as incurred. In contrast to a business combination (disposal), we classify a transaction as an asset acquisition (disposal) when substantially all the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. For asset acquisitions, we capitalize acquisition-related costs as a component of the cost of the assets acquired and liabilities assumed.
Noncontrolling interests	Noncontrolling interestsNoncontrolling interests represent the portion of our net income (loss), comprehensive income (loss) and net assets that is not allocable to us and is calculated based on our ownership percentage. For holdings where the economic allocations are not based pro rata on ownership percentages, we use the balance sheet-oriented hypothetical liquidation at book value (HLBV) method, to reflect the substantive profit sharing arrangement.Under the HLBV method, the amounts we report as "Noncontrolling interests" and "Net income (loss) attributable to noncontrolling interests" in our consolidated balance sheets and consolidated statements of income represent the amounts the noncontrolling interest would hypothetically receive at each balance sheet reporting date under the liquidation provisions of each holding’s ownership agreement assuming we were to liquidate the net assets of the projects at recorded amounts determined in accordance with U.S. GAAP and distribute those amounts to the investors. We determine the noncontrolling interest in our statements of income and comprehensive income as the difference in noncontrolling interests on our consolidated balance sheets at the start, or at inception of the noncontrolling interest if applicable, and end of each reporting period, after taking into account any capital transactions between the holdings and the third party. We report the noncontrolling interest balances in the holdings as a component of equity on our consolidated balance sheets.
Equity method investments	Equity method investmentsWe account for joint ventures that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as "Earnings (losses) from equity method investments." We recognize dividends received from joint ventures as a reduction in the carrying amount of the investment and not as dividend income. We assess and record an impairment of our equity method investments in earnings for a decline in value that we determine to be other than temporary.
Goodwill and other intangible assets	Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option to first perform a qualitative assessment to determine whether a quantitative assessment is necessary. If we determine, based on qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass the qualitative assessment, or perform the qualitative assessment but determine it is more likely than not that its fair value is less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four
Property, plant and equipment	Property, plant and equipment We account for property, plant and equipment at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and add an equal amount to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. We expense project costs during early stage development activities. Once we achieve certain development milestones and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. We periodically review development projects in construction for any indications of impairment. We transfer assets from “Construction work in progress” to “Property, plant and equipment” when they are available for service. We capitalize wind turbine and related equipment costs, other project construction costs and interest costs related to the project during the construction period through substantial completion. We record AROs at the date projects achieve commercial operation. We depreciate the cost of plant and equipment in use on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-55 Hydroelectric power stations 45-90 Wind power stations 25-40 Solar power stations 25 Transport facilities 40-75 Distribution facilities 15-80 Equipment Conventional meters and measuring devices 7-60 Computer software 4-25 Other Buildings 30-82 Operations offices 5-75 Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost of utility plant retired or otherwise disposed to accumulated depreciation. Networks' composite rate of depreciation was 2.9% of average depreciable property for both 2020 and 2019. We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs. Allowance for funds used during construction (AFUDC), applicable to Networks' entities that apply regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. We record the portion of AFUDC attributable to borrowed funds as a reduction of interest expense and record the remainder as other income.
Leases	Leases We determine if an arrangement is a lease at inception. We classify a lease as a finance lease if it meets any one of specified criteria that in essence transfers ownership of the underlying asset to us by the end of the lease term. If a lease does not meet any of those criteria, we classify it as an operating lease. On our consolidated balance sheets, we include, for operating leases: "Operating lease right-of-use (ROU) assets" and "Operating lease liabilities (current and non-current)"; and for finance leases: finance lease ROU assets in "Other assets" and liabilities in "Other current liabilities" and "Other liabilities." ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize lease ROU assets and liabilities at commencement of an arrangement based on the present value of lease payments over the lease term. Most of our leases do not provide an implicit rate, so we use our incremental borrowing rate based on the information available at the lease commencement date to determine the present value of future payments. A lease ROU asset also includes any lease payments made at or before commencement date, minus any lease incentives received, and includes initial direct costs incurred. We do not record leases with an initial term of 12 months or less on the balance sheet for all classes of underlying assets, and we recognize lease expense for those leases on a straight-line basis over the lease term. We include variable lease payments that depend on an index or a rate in the ROU asset and lease liability measurement based on the index or rate at the commencement date, or upon a modification. We do not include variable lease payments that do not depend on an index or a rate in the ROU asset and lease liability measurement. A lease term includes an option to extend or terminate the lease when it is reasonably certain that we will exercise that option. We recognize lease (rent) expense for operating lease payments on a straight-line basis over the lease term, or for our regulated companies we recognize the amount eligible for recovery under their rate plans, such as actual amounts paid. We amortize finance lease ROU assets on a straight-line basis over the lease term and recognize interest expense based on the outstanding lease liability. We have lease agreements with lease and non-lease components, and account for lease components and associated non-lease components together as a single lease component, for all classes of underlying assets.
Impairment of long-lived assets	Impairment of long-lived assetsWe evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. We are required to recognize an impairment loss if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow (DCF) model, with assumptions consistent with a market participant’s view of the exit price of the asset.
Fair value measurement	Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: • Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. • Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair valu e.
Equity investments with readily determinable fair values	Equity investments with readily determinable fair valuesWe measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income.
Derivatives and hedge accounting	Derivatives and hedge accounting Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met. Derivatives that qualify and are designated for hedge accounting are classified as cash flow hedges. We report the gain or loss on the derivative instrument as a component of Other Comprehensive Income (OCI) and later reclassify amounts into earnings when the underlying transaction occurs, which we present in the same income statement line item as the earnings effect of the hedged item. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, we will discontinue hedge accounting prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, we immediately recognize in earnings hedge gains and losses previously recorded in OCI. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. For our regulated operations, we record changes in the fair value of electric and natural gas hedge contracts derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement.
Cash and cash equivalents	Cash and cash equivalentsCash and cash equivalents include cash, bank accounts and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and include those investments in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on our consolidated balance sheets. We classify book overdrafts representing outstanding checks in excess of funds on deposit as “Accounts payable and accrued liabilities” on our consolidated balance sheets. We report changes in book overdrafts in the operating activities section of our consolidated statements of cash flows.
Trade receivable and unbilled revenue, net of allowance for credit losses	Trade receivable and unbilled revenue, net of allowance for credit losses We record trade receivables at amounts billed to customers and we record unbilled revenues based on an estimate of energy delivered or services provided to customers. Certain trade receivables and payables related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances and they are settled on a net basis. We present receivables and payables subject to such agreements on a net basis on our consolidated balance sheets. Trade receivables include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and we classify them as short term. Due to COVID-19, the UIL companies’ regulators require them to offer to customers, through early February 2021, a 24-month repayment plan. We establish our allowance for credit losses, including for unbilled revenue (also referred to as contract assets), by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. Due to our adoption of Accounting Standards Codification (ASC) 326 effective January 1, 2020, we now also consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the trade receivables. We write off amounts when we have exhausted reasonable collection efforts.
Variable interest entities	Variable interest entities An entity is considered to be a variable interest entity (VIE) when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses of or the right to receive benefits from the VIE that could potentially be significant to the VIE. We evaluate whether an entity is a VIE whenever reconsideration events occur as defined by the accounting guidance (See Note 20). We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as noncontrolling interests on our consolidated balance sheets. Subsequently, we use the HLBV method to allocate earnings to the noncontrolling interest, taking into consideration the cash and tax benefits provided to the tax equity investors.
Debentures, bonds and bank borrowings	Debentures, bonds and bank borrowingsWe record bonds, debentures and bank borrowings as a liability equal to the proceeds of the borrowings. We treat the difference between the proceeds and the face amount of the issued liability as discount or premium and accrete the amounts as interest expense or income over the life of the instrument. We defer incremental costs associated with the issuance of debt instruments and amortize them over the same period as debt discount or premium. We present bonds, debentures and bank borrowings net of unamortized discount, premium and debt issuance costs on our consolidated balance sheets.
Inventory	Inventory Inventory comprises fuel and gas in storage and materials and supplies. Through our gas operations, we own natural gas that is stored in third-party owned underground storage facilities, which we record as inventory. We price injections of inventory into storage at the market purchase cost at the time of injection, and price withdrawals of working gas from storage at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. We report inventories to support gas operations on our consolidated balance sheets within “Fuel and gas in storage.” We also have materials and supplies inventories that we use for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.” In addition, stand-alone renewable energy credits that are generated or purchased and held for sale are recorded at the lower of cost or net realizable value and are reported on our consolidated balance sheets within “Materials and supplies.”
Government grants and Deferred income	Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to the related utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, we recognize amounts receivable as an offset to expenses in our consolidated statements of income in the period in which we incur the expenses. (t ) Deferred income Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such revenues on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met.
Asset retirement obligations	Asset retirement obligations We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. We adjust the liability periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. We classify these as accrued removal obligations.
Environmental remediation liability	Environmental remediation liabilityIn recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. We record our environmental liabilities on an undiscounted basis. We expect to pay our environmental liability accruals through the year 2056.
Post-employment and other employee benefits	Post-employment and other employee benefits We sponsor defined benefit pension plans that cover eligible employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations generally reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. Unrecognized actuarial gains and losses related to the pension and other postretirement benefits plans are amortized over the average remaining service period or 10 years, considering any requirement by the regulators for our Networks subsidiaries. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five-year period.
Income taxes	Income taxes We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with U.S. GAAP for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. We defer the investment tax credits (ITCs) when earned and amortize them over the estimated lives of the related assets. We also recognize the income tax consequences of intra-entity transfers of assets other than inventory when the transfer occurs. Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. We record valuation allowances to reduce deferred tax assets when it is more likely than not that we will not realize all or a portion of a tax benefit. Deferred tax assets and liabilities are netted and classified as non-current on our consolidated balance sheets. We record the excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital in “Taxes other than income taxes” and “Taxes accrued” in our consolidated financial statements. Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax benefits are recorded within “Interest expense, net of capitalization” and “Other income and (expense)” in our consolidated statements of income. Uncertain tax positions have been classified as non-current unless expected to be paid within one year. In 2019, we netted our liability for uncertain tax positions against all same jurisdiction deferred tax assets, net operating losses and tax credit carryforwards. Our policy is to recognize interest and penalties on uncertain tax positions as a component of interest expense in the consolidated statements of income. Federal production tax credits applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in income tax expense with a corresponding reduction in deferred income tax liabilities. Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial statements.
Stock-based compensation	Stock-based compensationStock-based compensation represents costs related to stock-based awards granted to employees. We account for stock-based payment transactions based on the estimated fair value of awards reflecting forfeitures when they occur. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period, or until the employee becomes retirement eligible, if earlier.
Adoption of New Accounting Pronouncements and Accounting Pronouncements Issued But Not Yet Adopted	Adoption of New Accounting Pronouncements (a) Measurement of credit losses on financial instruments, amendments and updates The FASB issued an accounting standards update in June 2016 that requires more timely recording of credit losses on loans and other financial instruments (ASC 326). The amendments affect entities that hold financial assets and net investment in leases that are not accounted for at fair value through net income (loans, debt securities, trade receivables, net investments in leases, off-balance-sheet credit exposures, etc.). They require an entity to present a financial asset (or group of financial assets) that is measured at amortized cost basis at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset(s) to present the net carrying value at the amount expected to be collected on the financial asset. The income statement reflects the measurement of credit losses for newly recognized financial assets, as well as the expected increases or decreases of expected credit losses that have taken place during the period. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts that affect the collectability of the reported amount. An entity must use judgment in determining the relevant information and estimation methods appropriate in its circumstances. The FASB subsequently issued various updates to ASC 326 to clarify transition and scope requirements, make narrow-scope codification improvements, including in March 2020, and corrections and provide targeted transition relief. We adopted the amendments effective January 1, 2020, including the narrow-scope improvements issued in March 2020, and recorded a cumulative-effect adjustment of $1 million to retained earnings at the beginning of the period of adoption, with no material effect to our consolidated results of operations, financial position, cash flows and disclosures. (b) Simplifying the test for goodwill impairment In January 2017, the FASB issued amendments to simplify the test for goodwill impairment, which is required for public entities and certain other entities that have goodwill reported in their financial statements. The amendments simplify the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test, which requires the valuation of assets acquired and liabilities assumed using business combination accounting guidance. Under the new guidance, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; but the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Also, an entity should consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. Certain requirements are eliminated for any reporting unit with a zero or negative carrying amount; therefore, the same impairment assessment applies to all reporting units. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. We adopted the amendments effective January 1, 2020, with no material effect to our consolidated results of operations, financial position, cash flows and disclosures. As required, we are applying the amendments on a prospective basis. (c) Changes to the disclosure requirements for fair value measurement and defined benefit plans In August 2018, the FASB issued amendments related to disclosure requirements for both fair value measurement and defined benefit plans. The amendments concerning fair value measurement remove, modify and add certain disclosure requirements in order to improve the overall usefulness of the disclosures and reduce unnecessary costs to companies to prepare the disclosures. We adopted the amendments effective January 1, 2020, with no material effect to our disclosures. Certain amendments are to be applied prospectively, and all others are to be applied retrospectively. The amendments concerning disclosure requirements for defined benefit plans are narrow in scope and apply to all employers that sponsor defined benefit pension or other postretirement plans. The amendments change annual disclosures requirements, including removal of disclosures that are no longer considered cost beneficial, adding certain new relevant disclosures and clarifying specific requirements of disclosures concerning information for defined benefit pension plans. We adopted the amendments effective January 1, 2020, and they will not materially affect the disclosures for our fiscal year ending December 31, 2020. As required, we applied the amendments on a retrospective basis. (d) Targeted improvements to related party guidance for VIEs In October 2018, the FASB issued amendments that affect reporting entities that are required to determine whether they should consolidate a legal entity under the consolidation guidance applicable to VIEs. The targeted improvements specifically applicable to public business entities clarify that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. We adopted the amendments effective January 1, 2020, with no material effect to our consolidated results of operations, financial position, cash flows and disclosures. (e) Clarifying guidance for certain collaborative arrangements with respect to revenue recognition The FASB issued amendments in November 2018 to clarify the interaction between the guidance for certain collaborative arrangements and the guidance applicable to ASC 606. A collaborative arrangement is a contractual arrangement under which two or more parties actively participate in a joint operating activity and are exposed to significant risks and rewards that depend on the activity’s commercial success. The targeted improvements clarify that certain transactions between collaborative arrangement participants are within the scope of ASC 606 and thus subject to all its guidance. We adopted the amendments effective January 1, 2020, with no material effect to our consolidated results of operations, financial position, cash flows and disclosures. As required, we retrospectively applied the amendments to the date of our initial application of ASC 606. Accounting Pronouncements Issued But Not Yet Adopted The following are new accounting pronouncements not yet adopted that we have evaluated or are evaluating to determine their effect on our consolidated financial statements. (a) Simplifying the accounting for income taxes In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes , eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation, (2) exceptions to accounting for basis differences in equity method investments when there are ownership changes in foreign investments and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for (1) franchise taxes that are partially based on income, (2) transactions with a government that result in a step up in the tax basis of goodwill, (3) separate financial statements of legal entities that are not subject to tax and (4) enacted changes in tax laws in interim periods. The amendments are effective for public business entities for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued, with adoption of all amendments in the same period. Application is on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment aspect. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows. (b) Facilitation of the effects of reference rate reform on financial reporting, 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.
Use of Estimates and Assumptions	Use of Estimates and Assumptions The preparation of our consolidated financial statements in conformity with U.S. GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. Significant estimates and assumptions are used for, but not limited to: (1) allowance for credit losses and unbilled revenues; (2) asset impairments, including goodwill; (3) investments in equity instruments; (4) depreciable lives of assets; (5) income tax valuation allowances; (6) uncertain tax positions; (7) reserves for professional, workers’ compensation and comprehensive general insurance liability risks; (8) contingency and litigation reserves; (9) fair value measurements; (10) earnings sharing mechanisms; (11) environmental remediation liabilities; (12) AROs; (13) pension and other postretirement employee benefits and (14) noncontrolling interest balances. Future events and their effects cannot be predicted with certainty; accordingly, our accounting estimates require the exercise of judgment. The accounting estimates we use in the preparation of our consolidated financial statements will change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We evaluate and update our assumptions and estimates on an ongoing basis and may employ outside specialists to assist in our evaluations, as necessary. Actual results could differ from those estimates. We continue to utilize information reasonably available to us; however, the business and economic uncertainty resulting from COVID-19 has made such estimates and assumptions more difficult to assess and calculate. Affected 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 we have not yet had material effects of COVID-19 on our financial results, actual results could differ from those estimates, which could result in material effects to our consolidated financial statements in future reporting periods.
Union collective bargaining agreements	Union collective bargaining agreements We have approximately 48.8% of our employees covered by a collective bargaining agreement. Agreements expiring in the coming year apply to approximately 16.0% of our employees.

Basis of Presentation (Tables)

Basis of Presentation (Tables)	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Error Corrections and Prior Period Adjustments	A summary of the effect of the correction on the consolidated balance sheet as of December 31, 2019 is as follows: As of December 31, 2019 As reported Correction As Revised (Millions) Assets Total Property, Plant and Equipment $ 25,218 $ (22) $ 25,196 Total Assets $ 34,416 $ (22) $ 34,394 Liabilities Other current liabilities $ 334 $ 2 $ 336 Total Current Liabilities $ 3,587 $ 2 $ 3,589 Deferred income taxes $ 1,814 $ 23 $ 1,837 Total Other Non-current Liabilities $ 5,246 $ 23 $ 5,269 Total Non-current Liabilities $ 15,243 $ 23 $ 15,266 Total Liabilities $ 18,830 $ 25 $ 18,855 Equity Retained earnings $ 1,681 $ (47) $ 1,634 Total Stockholders’ Equity $ 15,237 $ (47) $ 15,190 Total Equity $ 15,586 $ (47) $ 15,539 Total Liabilities and Equity $ 34,416 $ (22) $ 34,394 A summary of the effect of the correction on the consolidated statements of income for the year ended December 31, 2019 is as follows: Year Ended December 31, 2019 As reported Correction As Revised (Millions) Operating Revenues $ 6,338 $ (2) $ 6,336 Operations and maintenance $ 2,301 $ 4 $ 2,305 Depreciation and amortization $ 934 $ (1) $ 933 Total Operating Expenses $ 5,335 $ 3 $ 5,338 Operating Income $ 1,003 $ (5) $ 998 Other income $ 119 $ 2 $ 121 Interest expense, net of capitalization $ (306) $ (4) $ (310) Income Before Income Tax $ 819 $ (7) $ 812 Income tax expense $ 143 $ 26 $ 169 Net Income $ 676 $ (33) $ 643 Net Income Attributable to Avangrid, Inc. $ 700 $ (33) $ 667 Earnings per common share, Basic $ 2.26 $ (0.10) $ 2.16 Earnings per common share, Diluted $ 2.26 $ (0.10) $ 2.16 A summary of the effect of the correction on the consolidated statements of income for the year ended December 31, 2018 is as follows: Year Ended December 31, 2018 As reported Correction As Revised (Millions) Operating Revenues $ 6,478 $ (1) $ 6,477 Operations and maintenance $ 2,248 $ 10 $ 2,258 Total Operating Expenses $ 5,351 $ 10 $ 5,361 Operating Income $ 1,127 $ (11) $ 1,116 Income Before Income Tax $ 768 $ (11) $ 757 Income tax expense $ 170 $ (3) $ 167 Net Income $ 598 $ (8) $ 590 Net Income Attributable to Avangrid, Inc. $ 595 $ (8) $ 587 Earnings per common share, Basic $ 1.92 $ (0.02) $ 1.90 Earnings per common share, Diluted $ 1.92 $ (0.03) $ 1.89 A summary of the effect of the correction on the consolidated statements of cash flows for the years ended December 31, 2019 and 2018 is as follows: Years Ended December 31, 2019 2018 (Millions) As Reported Correction As Revised As Reported Correction As Revised Net income $ 676 $ (33) $ 643 $ 598 $ (8) $ 590 Depreciation and amortization $ 934 $ (1) $ 933 $ 855 $ — $ 855 Deferred taxes $ 138 $ 26 $ 164 $ 151 $ (3) $ 148 Current liabilities $ (5) $ 3 $ (2) $ 98 $ 1 $ 99 Net Cash Provided by Operating Activities $ 1,593 $ (5) $ 1,588 $ 1,791 $ (10) $ 1,781 Capital expenditures $ (2,740) $ 5 $ (2,735) $ (1,787) $ 10 $ (1,777) Net Cash Used in Investing Activities $ (2,713) $ 5 $ (2,708) $ (1,564) $ 10 $ (1,554) Cash paid for interest, net of amounts capitalized $ 266 $ 4 $ 270 $ 224 $ — $ 224

Summary of Significant Accoun_3

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates (Tables)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Schedule of Estimated Useful Lives	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-55 Hydroelectric power stations 45-90 Wind power stations 25-40 Solar power stations 25 Transport facilities 40-75 Distribution facilities 15-80 Equipment Conventional meters and measuring devices 7-60 Computer software 4-25 Other Buildings 30-82 Operations offices 5-75 Property, plant and equipment as of December 31, 2020, consisted of: As of December 31, 2020 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 16,364 $ 12,854 $ 29,218 Natural gas transportation, distribution and other 4,637 13 4,650 Other common operating property — 274 274 Total Property, Plant and Equipment in Service 21,001 13,141 34,142 Total accumulated depreciation (5,363) (4,436) (9,799) Total Net Property, Plant and Equipment in Service 15,638 8,705 24,343 Construction work in progress 1,384 1,024 2,408 Total Property, Plant and Equipment $ 17,022 $ 9,729 $ 26,751 Property, plant and equipment as of December 31, 2019, consisted of: As of December 31, 2019 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 15,092 $ 12,360 $ 27,452 Natural gas transportation, distribution and other 4,373 13 4,386 Other common operating property — 258 258 Total Property, Plant and Equipment in Service 19,465 12,631 32,096 Total accumulated depreciation (4,968) (4,090) (9,058) Total Net Property, Plant and Equipment in Service 14,497 8,541 23,038 Construction work in progress 1,271 887 2,158 Total Property, Plant and Equipment $ 15,768 $ 9,428 $ 25,196

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Schedule of Revenues Disaggregated by Major Source for Reportable Segments	Revenues disaggregated by major source for our reportable segments for the years ended December 31, 2020, 2019 and 2018 are as follows: Year Ended December 31, 2020 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,642 $ — $ — $ 3,642 Regulated operations – natural gas 1,311 — — 1,311 Nonregulated operations – wind — 822 — 822 Nonregulated operations – solar — 19 — 19 Nonregulated operations – thermal — 39 — 39 Other (a) 58 101 — 159 Revenue from contracts with customers 5,011 981 — 5,992 Leasing revenue 6 — — 6 Derivative revenue — 136 — 136 Alternative revenue programs 157 — — 157 Other revenue 14 15 — 29 Total operating revenues $ 5,188 $ 1,132 $ — $ 6,320 Year Ended December 31, 2019 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,485 $ — $ — $ 3,485 Regulated operations – natural gas 1,479 — — 1,479 Nonregulated operations – wind — 803 — 803 Nonregulated operations – solar — 26 — 26 Nonregulated operations – thermal — 29 — 29 Other (a) 91 62 (12) 141 Revenue from contracts with customers 5,055 920 (12) 5,963 Leasing revenue 6 — — 6 Derivative revenue — 244 — 244 Alternative revenue programs 75 — — 75 Other revenue 28 20 — 48 Total operating revenues $ 5,164 $ 1,184 $ (12) $ 6,336 Year Ended December 31, 2018 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,641 $ — $ — $ 3,641 Regulated operations – natural gas 1,473 — — 1,473 Nonregulated operations – wind — 636 — 636 Nonregulated operations – solar — 17 — 17 Nonregulated operations – thermal — 47 — 47 Nonregulated operations – gas storage — — 10 10 Other (a) 58 (68) 9 (1) Revenue from contracts with customers 5,172 632 19 5,823 Leasing revenue 38 346 — 384 Derivative revenue — 124 10 134 Alternative revenue programs 80 — — 80 Other revenue 20 36 — 56 Total operating revenues $ 5,310 $ 1,138 $ 29 $ 6,477 (a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate, Gas (for 2018 only) and intersegment eliminations.
Schedule of Aggregate Transaction Price Allocations	As of December 31, 2020, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of December 31, 2020 2021 2022 2023 2024 2025 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ 1 $ 1 $ 1 $ — $ — $ 4 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 31 23 13 4 3 5 79 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 40 24 16 14 12 75 182 Total operating revenues $ 72 $ 48 $ 30 $ 19 $ 15 $ 80 $ 265

Industry Regulation (Tables)

Industry Regulation (Tables)	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Schedule of Delivery Rate Increases	The delivery rate increases for the last year of the 2016 Joint Proposal can be summarized as follows: May 1, 2018 Rate Increase Delivery Rate Increase Utility (Millions) % NYSEG Electric $ 30 4.10 % NYSEG Gas $ 15 7.30 % RG&E Electric $ 26 5.70 % RG&E Gas $ 10 5.20 % Year 1 Year 2 Year 3 Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Utility (Millions) % (Millions) % (Millions) % NYSEG Electric $ 34 4.6 % $ 46 5.9 % $ 36 4.2 % NYSEG Gas $ — — % $ 2 0.8 % $ 3 1.6 % RG&E Electric $ 17 3.8 % $ 14 3.2 % $ 16 3.3 % RG&E Gas $ — — % $ — — % $ 2 1.3 %

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Schedule of Regulatory Assets	Regulatory assets as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Pension and other post-retirement benefits cost deferrals $ 105 $ 125 Pension and other post-retirement benefits 927 1,061 Storm costs 451 272 Rate adjustment mechanism 33 79 Revenue decoupling mechanism 58 19 Transmission revenue reconciliation mechanism 31 5 Contracts for differences 86 92 Hardship programs 20 29 Plant decommissioning 3 5 Deferred purchased gas 30 25 Deferred transmission expense 26 11 Environmental remediation costs 247 277 Debt premium 83 97 Unamortized losses on reacquired debt 26 29 Unfunded future income taxes 373 399 Federal tax depreciation normalization adjustment 148 153 Asset retirement obligation 21 17 Deferred meter replacement costs 33 27 COVID-19 cost recovery 1 — Other 180 139 Total regulatory assets 2,882 2,861 Less: current portion 310 294 Total non-current regulatory assets $ 2,572 $ 2,567
Schedule of Regulatory Liabilities	Regulatory liabilities as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Energy efficiency portfolio standard $ 58 $ 72 Gas supply charge and deferred natural gas cost 3 11 Pension and other post-retirement benefits cost deferrals 59 80 Carrying costs on deferred income tax bonus depreciation 34 49 Carrying costs on deferred income tax - Mixed Services 263(a) 11 15 2017 Tax Act 1,435 1,548 Rate change levelization 55 10 Revenue decoupling mechanism 9 17 Accrued removal obligations 1,184 1,173 Asset sale gain account 7 10 Economic development 28 27 Positive benefit adjustment 30 37 Theoretical reserve flow thru impact 10 14 Deferred property tax 31 17 Net plant reconciliation 20 23 Debt rate reconciliation 63 67 Rate refund – FERC ROE proceeding 33 32 Transmission congestion contracts 22 23 Merger-related rate credits 14 16 Accumulated deferred investment tax credits 25 13 Asset retirement obligation 18 14 Earnings sharing provisions 17 28 Middletown/Norwalk local transmission network service collections 18 18 Low income programs 28 33 Non-firm margin sharing credits 14 16 New York 2018 winter storm settlement 9 11 Other 176 149 Total regulatory liabilities 3,411 3,523 Less: current portion 274 242 Total non-current regulatory liabilities $ 3,137 $ 3,281

Goodwill and Intangible assets

Goodwill and Intangible assets (Tables)	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill by Reportable Segment	Goodwill by reportable segment as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Networks $ 2,747 $ 2,747 Renewables 372 372 Total $ 3,119 $ 3,119
Schedule of Intangible Assets Acquired and Developed	Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets as of December 31, 2020 and 2019: As of December 31, 2020 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 593 $ (290) $ 303 Other 31 (29) 2 Total Intangible Assets $ 624 $ (319) $ 305 As of December 31, 2019 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 591 $ (289) $ 302 Other 28 (16) 12 Total Intangible Assets $ 619 $ (305) $ 314
Schedule of Expect Amortization Expense	We expect amortization expense for the five years subsequent to December 31, 2020, to be as follows: Year ending December 31, Amount (Millions) 2021 $ 14 2022 $ 13 2023 $ 12 2024 $ 12 2025 $ 12

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-55 Hydroelectric power stations 45-90 Wind power stations 25-40 Solar power stations 25 Transport facilities 40-75 Distribution facilities 15-80 Equipment Conventional meters and measuring devices 7-60 Computer software 4-25 Other Buildings 30-82 Operations offices 5-75 Property, plant and equipment as of December 31, 2020, consisted of: As of December 31, 2020 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 16,364 $ 12,854 $ 29,218 Natural gas transportation, distribution and other 4,637 13 4,650 Other common operating property — 274 274 Total Property, Plant and Equipment in Service 21,001 13,141 34,142 Total accumulated depreciation (5,363) (4,436) (9,799) Total Net Property, Plant and Equipment in Service 15,638 8,705 24,343 Construction work in progress 1,384 1,024 2,408 Total Property, Plant and Equipment $ 17,022 $ 9,729 $ 26,751 Property, plant and equipment as of December 31, 2019, consisted of: As of December 31, 2019 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 15,092 $ 12,360 $ 27,452 Natural gas transportation, distribution and other 4,373 13 4,386 Other common operating property — 258 258 Total Property, Plant and Equipment in Service 19,465 12,631 32,096 Total accumulated depreciation (4,968) (4,090) (9,058) Total Net Property, Plant and Equipment in Service 14,497 8,541 23,038 Construction work in progress 1,271 887 2,158 Total Property, Plant and Equipment $ 15,768 $ 9,428 $ 25,196

Asset retirement obligations (T

Asset retirement obligations (Tables)	12 Months Ended
	Dec. 31, 2020
Table Text Block Supplement [Abstract]
Schedule of Asset Retirement Obligations	The reconciliation of ARO carrying amounts for the years ended December 31, 2020 and 2019 consisted of: (Millions) As of December 31, 2018 $ 217 Liabilities settled during the year (5) Liabilities incurred during the year 6 Accretion expense 12 Revisions in estimated cash flows (a) (40) As of December 31, 2019 $ 190 Liabilities settled during the year (2) Liabilities incurred during the year 9 Accretion expense 11 Revisions in estimated cash flows (a) 2 As of December 31, 2020 $ 210 (a) Represents a reduction in our estimate of expected cash flows required for retirement activities related to our renewable energy facilities.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long-term debt as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 Maturity Dates Balances Interest Rates Balances Interest Rates (Millions) First mortgage bonds - fixed (a) 2021-2049 $ 2,575 1.85%-8.00% $ 2,218 3.07%-8.00% Unsecured pollution control notes - fixed 2023-2029 478 1.40%-3.50% 538 2.00%-3.50% Term loan - variable — 500 2.40% Other various non-current debt - fixed 2021-2050 4,785 1.95%-7.80% 4,228 2.80%-10.48% Unamortized debt issuance costs and discount (47) (38) Total Debt 7,791 7,446 Less: debt due within one year, included in current liabilities 313 730 Total Non-current Debt $ 7,478 $ 6,716 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $7,483 million. Other 2020 Long-Term Debt Issuances Company Issue Date Type Amount (Millions) Interest rate Maturity AVANGRID 4/9/2020 Unsecured Notes $ 750 3.20 % 2025 NYSEG (1) 5/1/2020 Pollution Control Bonds $ 200 1.40% - 1.61% 2026 -2029 BGC 9/1/2020 Unsecured Notes $ 25 3.68 % 2050 NYSEG 9/25/2020 Unsecured Notes $ 200 1.95 % 2030 RG&E 11/23/2020 First Mortgage Bonds $ 200 1.85 % 2030 UI 12/1/2020 Unsecured Notes $ 75 2.02 % 2030 CMP 12/15/2020 First Mortgage Bonds $ 50 1.87 % 2030 CNG 12/15/2020 Unsecured Notes $ 30 2.02 % 2030 SCG 12/15/2020 First Mortgage Bonds $ 50 1.87 % 2030 (1) Non-cash remarketing of bonds to reset interest rates.
Schedule of Maturities and Repayments of Long-term Debt	Long-term debt maturities, including sinking fund obligations, due over the next five years consist of: 2021 2022 2023 2024 2025 Total (Millions) $ 313 $ 363 $ 439 $ 612 $ 1,107 $ 2,834

Fair Value of Financial Instr_2

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other 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) Derivative financial instruments – Other — — — — — Total $ (24) $ (40) $ (113) $ 81 $ (96) As of December 31, 2019 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 38 $ 13 $ — $ — $ 51 Derivative assets Derivative financial instruments - power $ 4 $ 23 $ 120 $ (54) $ 93 Derivative financial instruments - gas — 40 31 (71) — Contracts for differences — — 2 — 2 Total $ 4 $ 63 $ 153 $ (125) $ 95 Derivative liabilities Derivative financial instruments - power $ (28) $ (43) $ (29) $ 92 $ (8) Derivative financial instruments - gas (4) (26) (5) 33 (2) Contracts for differences — — (94) — (94) Derivative financial instruments – Other — (1) — — (1) Total $ (32) $ (70) $ (128) $ 125 $ (105)
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 years ended December 31, 2020, 2019 and 2018 consisted of: (Millions) 2020 2019 2018 Fair value as of January 1, $ 25 $ (15) $ 6 Gains for the year recognized in operating revenues 8 53 18 Losses for the year recognized in operating revenues (2) (2) (9) Total gains or losses for the period recognized in operating revenues 6 51 9 Gains recognized in OCI 1 2 — Losses recognized in OCI (3) (3) (5) Total gains or losses recognized in OCI (2) (1) (5) Net change recognized in regulatory assets and liabilities 6 5 (5) Purchases (2) (22) (6) Settlements (15) 4 (10) Transfers out of Level 3 (a) (5) 3 (4) Fair value as of December 31, $ 13 $ 25 $ (15) Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ 6 $ 51 $ 9 (a) Transfers out of Level 3 were the result of increased observability of market data. Range at Unobservable Input December 31, 2020 Risk of non-performance 0.50% - 0.51% Discount rate 0.17% - 0.36% Forward pricing ($ per KW-month) $2.00 - $5.30
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques	The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives as of December 31, 2020. Index Avg. Max. Min. NYMEX ($/MMBtu) $ 2.53 $ 3.47 $ 1.48 AECO ($/MMBtu) $ 1.45 $ 3.24 $ (0.17) Ameren ($/MWh) $ 26.12 $ 40.53 $ 14.73 COB ($/MWh) $ 33.30 $ 95.00 $ 8.20 ComEd ($/MWh) $ 24.10 $ 39.26 $ 12.65 ERCOT N hub ($/MWh) $ 32.19 $ 196.95 $ 11.25 ERCOT S hub ($/MWh) $ 32.55 $ 203.37 $ 11.41 Indiana hub ($/MWh) $ 28.23 $ 43.58 $ 16.36 Mid C ($/MWh) $ 29.76 $ 95.00 $ 4.00 Minn hub ($/MWh) $ 22.82 $ 37.78 $ 11.52 NoIL hub ($/MWh) $ 24.00 $ 39.01 $ 12.70 PJM W hub ($/MWh) $ 28.46 $ 59.53 $ 14.28

Derivative Instruments and He_2

Derivative Instruments and Hedging (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Consolidated Balance Sheet and Amounts	The tables below present Networks' derivative positions as of December 31, 2020 and 2019, respectively, including those subject to master netting agreements and the location of the net derivative positions on our consolidated balance sheets: As of December 31, 2020 Current Assets Noncurrent Assets Current Liabilities Noncurrent 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) As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 1 $ 4 $ 1 $ 2 Derivative liabilities (1) (2) (39) (86) — 2 (38) (84) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (1) (1) — — (1) (1) Total derivatives before offset of cash collateral — 2 (39) (85) Cash collateral receivable — — 27 1 Total derivatives as presented in the balance sheet $ — $ 2 $ (12) $ (84) The tables below present Renewables' derivative positions as of December 31, 2020 and 2019, respectively, including those subject to master netting agreements and the location of the net derivative position on our consolidated balance sheets: As of December 31, 2020 Current Assets Noncurrent Assets Current Liabilities Noncurrent 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 assets 8 15 2 7 Derivative liabilities (5) (6) (3) (10) 3 9 (1) (3) Total derivatives before offset of cash collateral 27 96 (3) (5) Cash collateral payable (9) (18) — — Total derivatives as presented in the balance sheet $ 18 $ 78 $ (3) $ (5) As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 23 $ 110 $ 42 $ 13 Derivative liabilities (1) (7) (48) (18) 22 103 (6) (5) Designated as hedging instruments Derivative assets — 18 5 4 Derivative liabilities — (9) (13) (6) — 9 (8) (2) Total derivatives before offset of cash collateral 22 112 (14) (7) Cash collateral (payable) receivable (11) (30) 7 6 Total derivatives as presented in the balance sheet $ 11 $ 82 $ (7) $ (1)
Schedule of Notional Volumes of Outstanding Derivative Positions	The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of December 31, 2020 and 2019, respectively, consisted of: As of December 31, 2020 2019 (Millions) Wholesale electricity purchase contracts (MWh) 5.6 5.1 Natural gas purchase contracts (Dth) 9.5 8.5 Fleet fuel purchase contracts (Gallons) 2.5 2.2 The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of December 31, 2020 and 2019, respectively, consisted of: As of December 31, 2020 2019 (MWh/Dth in Millions) Wholesale electricity purchase contracts 3 4 Wholesale electricity sales contracts 7 9 Natural gas and other fuel purchase contracts 24 29 Financial power contracts 12 10 Basis swaps - purchases 35 42 Basis swaps - sales 2 1
Summary of Unrealized Gains and Losses from Fair Value Adjustments	The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of December 31, 2020 and 2019 and amounts reclassified from regulatory assets and liabilities into income for the years ended 2020, 2019 and 2018 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of For the Year Ended December 31, December 31, 2020 Electricity Natural Gas 2020 Electricity Natural Gas Regulatory assets $ 17 $ 1 Purchased power, natural gas and fuel used $ 55 $ 4 Regulatory liabilities $ — $ — December 31, 2019 2019 Regulatory assets $ 24 $ 4 Purchased power, natural gas and fuel used $ 25 $ 1 Regulatory liabilities $ — $ — 2018 Purchased power, natural gas and fuel used $ (10) $ (1) The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the years ended December 31, 2020, 2019 and 2018, respectively, were as follows: Years Ended December 31, 2020 2019 2018 (Millions) Derivative Assets $ — $ (3) $ (6) Derivative Liabilities $ 6 $ 8 $ 1
Derivative Instruments, Gain (Loss)	The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2020, 2019 and 2018, respectively, consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2020 Interest rate contracts $ — Interest expense $ 4 $ 316 Commodity contracts (1) Purchased power, natural gas and fuel used 1 1,379 Foreign currency exchange contracts 1 — Total $ — $ 5 2019 Interest rate contracts $ — Interest expense $ 6 $ 310 Commodity contracts — Purchased power, natural gas and fuel used 1 1,509 Foreign currency exchange contracts (1) — Total $ (1) $ 7 2018 Interest rate contracts $ — Interest expense $ 8 $ 303 Commodity contracts (1) Purchased power, natural gas and fuel used — 1,653 Total $ (1) $ 8 (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 years ended December 31, 2020, 2019 and 2018 consisted of: Year Ended December 31, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss (Gain) Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2020 Commodity contracts $ 1 Operating revenues $ 6 $ 6,320 2019 Commodity contracts $ (5) Operating revenues $ 3 $ 6,336 2018 Commodity contracts $ (11) Operating revenues $ (22) $ 6,477 (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 years ended December 31, 2020 and 2019, respectively, consisted of: Years Ended December 31, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2020 Interest rate contracts $ (27) Interest expense $ 8 $ 316 2019 Interest rate contracts $ (24) Interest expense $ 2 $ 310 2018 Interest rate contracts $ (16) Interest expense $ — $ 303 (a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI is being reclassified into earnings over the underlying debt maturity periods which ends in 2025 and 2029.
Schedule of Fair Value, Net Derivative Contracts	The fair values of derivative contracts associated with Renewables' activities as of December 31, 2020 and 2019, respectively, consisted of: As of December 31, 2020 2019 (Millions) Wholesale electricity purchase contracts $ 4 $ 10 Wholesale electricity sales contracts 11 4 Natural gas and other fuel purchase contracts — (2) Financial power contracts 66 73 Basis swaps - purchases 7 — Total $ 88 $ 85
Effect of Derivatives Associated with Renewables and Gas Activities	The effects of trading and non-trading derivatives associated with Renewables' activities for the year ended December 31, 2020, consisted of: Year Ended December 31, 2020 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1) $ — Wholesale electricity sales contracts (1) 6 Financial power contracts 2 — Financial and natural gas contracts — (13) Total loss included in operating revenues $ — $ (7) $ 6,320 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (4) Financial and natural gas contracts — 6 Total gain included in purchased power, natural gas and fuel used $ — $ 2 $ 1,379 Total Loss $ — $ (5) Year Ended December 31, 2019 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1) $ — Wholesale electricity sales contracts 3 40 Financial power contracts (3) 23 Financial and natural gas contracts (1) 1 Total (loss) gain included in operating revenues $ (2) $ 64 $ 6,336 Purchased power, natural gas and fuel used Financial power contracts — (1) Financial and natural gas contracts — 15 Total gain included in purchased power, natural gas and fuel used $ — $ 14 $ 1,509 Total (Loss) Gain $ (2) $ 78 During September 2019, Renewables liquidated a portion of one of its wholesale electricity sales contracts and recorded a gain of $43 million for the year ended December 31, 2019. The effects of trading and non-trading derivatives associated with Renewables activities for the years ended December 31, 2018 consisted of: Years Ended December 31, 2018 (Millions) Trading Non-trading Wholesale electricity purchase contracts $ 4 $ 11 Wholesale electricity sales contracts (2) (15) Financial power contracts — (19) Financial and natural gas contracts 4 — Total Gain (Loss) $ 6 $ (23)

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Lease, Cost	The components of lease cost for the years ended December 31, 2020 and 2019 were as follows: For the Year Ended December 31, 2020 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 17 $ 12 Interest on lease liabilities 4 3 Total finance lease cost 21 15 Operating lease cost 16 18 Short-term lease cost 3 5 Variable lease cost — 2 Total lease cost $ 40 $ 40 For the years ended December 31, 2020 and 2019, supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2020 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 13 $ 13 Operating cash flows from finance leases $ 3 $ 3 Financing cash flows from finance leases $ 9 $ 27 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ 46 $ 1 Operating leases $ 94 $ 3
Assets And Liabilities, Lessee	Balance sheet and other information for the years ended December 31, 2020 and 2019 was as follows: As of December 31, 2020 2019 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 153 $ 70 Operating lease liabilities, current 8 12 Operating lease liabilities, long-term 154 65 Total operating lease liabilities $ 162 $ 77 Finance Leases Other assets $ 162 $ 133 Other current liabilities 8 9 Other non-current liabilities 91 54 Total finance lease liabilities $ 99 $ 63 Weighted-average Remaining Lease Term (years) Finance leases 8.12 7.59 Operating leases 21.38 12.98 Weighted-average Discount Rate Finance leases 3.71 % 5.35 % Operating leases 3.21 % 3.62 %
Finance Lease Maturity	As of December 31, 2020, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2021 $ 10 $ 15 2022 5 15 2023 53 13 2024 23 10 2025 2 10 Thereafter 19 182 Total lease payments 112 245 Less: imputed interest (13) (83) Total $ 99 $ 162
Operating Lease Maturity	As of December 31, 2020, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2021 $ 10 $ 15 2022 5 15 2023 53 13 2024 23 10 2025 2 10 Thereafter 19 182 Total lease payments 112 245 Less: imputed interest (13) (83) Total $ 99 $ 162

Commitments and Contingent Li_2

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Forward Purchase and Sales Commitment Arrangement	Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2020 consisted of: Year Purchases Sales (Millions) 2021 $ 889 $ 178 2022 135 103 2023 74 68 2024 48 41 2025 45 32 Thereafter 934 54 Totals $ 2,125 $ 476

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Schedule of Current and Deferred Taxes Charged to (Benefit) Expense	Current and deferred taxes charged to expense for the years ended December 31, 2020, 2019 and 2018 consisted of: Years Ended December 31, 2020 2019 2018 (Millions) Current Federal $ 3 $ 11 $ 17 State 9 (6) 2 Current taxes charged to expense 12 5 19 Deferred Federal 67 164 231 State 38 58 (13) Deferred taxes charged to expense 105 222 218 Production tax credits (87) (57) (68) Investment tax credits (1) (1) (2) Total Income Tax Expense $ 29 $ 169 $ 167
Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate	The differences between tax expense per the statements of income and tax expense at the 21% statutory federal tax rate for the years ended December 31, 2020, 2019 and 2018 consisted of: Years Ended December 31, 2020 2019 2018 (Millions) Tax expense at federal statutory rate $ 119 $ 170 $ 159 Depreciation and amortization not normalized (13) (23) (5) Investment tax credit amortization (1) (1) (2) Tax return related adjustments 1 (2) (6) Production tax credits (87) (57) (68) Tax equity financing arrangements 1 8 — Federal tax rate impact on held for sale classification — — 21 State tax expense (benefit), net of federal benefit 37 41 (9) Excess ADIT amortization (42) — — Tax Act - remeasurement — — 46 Other, net 14 33 31 Total Income Tax Expense $ 29 $ 169 $ 167
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Deferred Income Tax Liabilities (Assets) Property related $ 4,147 $ 4,007 Unfunded future income taxes 100 101 Federal and state tax credits (731) (632) Federal and state NOL’s (1,047) (981) Joint ventures/partnerships 167 136 Nontaxable grant revenue (311) (335) Pension and other post-retirement benefits 22 43 Tax Act - tax on regulatory remeasurement (382) (409) Valuation allowance 81 48 Other (127) (141) Deferred Income Tax Liabilities $ 1,919 $ 1,837 Deferred tax assets $ 2,598 $ 2,498 Deferred tax liabilities 4,517 4,335 Net Accumulated Deferred Income Tax Liabilities $ 1,919 $ 1,837
Schedule of Reconciliation of Unrecognized Income Tax Benefits	The reconciliation of unrecognized income tax benefits for the years ended December 31, 2020, 2019 and 2018 consisted of: Years ended December 31, 2020 2019 2018 (Millions) Beginning Balance $ 148 $ 153 $ 45 Increases for tax positions related to prior years 11 14 111 Increases for tax positions related to current year — 16 — Decreases for tax positions related to prior years (32) (18) (3) Reduction for tax position related to settlements with taxing authorities — (17) — Ending Balance $ 127 $ 148 $ 153

Post-retirement and Similar O_2

Post-retirement and Similar Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
Obligations and Funded Status	As of December 31, 2020 and 2019, our obligations and funded status consisted of: Pension Benefits Postretirement Benefits As of December 31, 2020 2019 2020 2019 (Millions) Change in benefit obligation Benefit Obligation as of January 1, $ 3,669 $ 3,374 $ 439 $ 425 Service cost 47 41 3 3 Interest cost 107 130 13 16 Plan amendments 7 (2) — — Actuarial loss 236 347 29 26 Curtailments (21) — — — Benefits paid (226) (221) (32) (31) Benefit Obligation as of December 31, 3,819 3,669 452 439 Change in plan assets Fair Value of Plan Assets as of January 1, 2,848 2,544 155 148 Actual return on plan assets 388 460 26 22 Employer contributions 84 65 18 16 Curtailments (2) — — — Benefits paid (226) (221) (32) (31) Fair Value of Plan Assets as of December 31, 3,092 2,848 167 155 Funded Status as of December 31, $ (727) $ (821) $ (285) $ (284)
Schedule of Amounts Recognized in Balance Sheet	As of December 31, 2020 and 2019, funded status amounts recognized on our consolidated balance sheets consisted of: Pension Benefits Postretirement Benefits As of December 31, 2020 2019 2020 2019 (Millions) Current liabilities $ — $ — $ (5) $ (5) Non-current liabilities (727) (821) (280) (279) Total $ (727) $ (821) $ (285) $ (284)
Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations	Amounts recognized as a component of regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2020 and 2019 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2020 2019 2020 2019 (Millions) Net loss $ 610 $ 706 $ 14 $ 13 Prior service cost (credit) $ 10 $ 4 $ (8) $ (21) Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2020, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2020 2019 2018 2020 2019 2018 (Millions) Net Periodic Benefit Cost: Service cost $ 46 $ 41 $ 44 $ 3 $ 3 $ 4 Interest cost 106 128 126 13 16 18 Expected return on plan assets (198) (190) (199) (8) (7) (8) Amortization of prior service cost (benefit) 1 (1) 1 (9) (10) (9) Amortization of net loss 124 113 149 2 1 6 Net Periodic Benefit Cost 79 91 121 1 3 11 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Curtailments (18) — — — — — Net loss (gain) 46 80 175 11 13 (37) Amortization of net loss (124) (113) (149) (2) (1) (6) Current year prior service cost (credit) 7 (2) — — — (3) Amortization of prior service (cost) benefit (1) 1 (1) 9 10 9 Total Other Changes (90) (34) 25 18 22 (37) Total Recognized $ (11) $ 57 $ 146 $ 19 $ 25 $ (26) Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2020, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2020 2019 2018 2020 2019 2018 (Millions) Net Periodic Benefit Cost: Service cost $ 1 $ 1 $ — $ — $ — $ — Interest cost 1 2 2 — — 1 Expected return on plan assets (2) (2) (2) — — — Amortization of net loss (gain) 2 1 1 (1) (1) — Settlement charge 1 — 1 — — — Net Periodic Benefit Cost 3 2 2 (1) (1) 1 Other Changes in plan assets and benefit obligations recognized in OCI: Net loss (gain) 1 — 1 — — (3) Amortization of net (loss) gain (2) (1) (1) 1 1 — Amortization of prior service cost — — — — (2) — Total Other Changes (1) (1) — 1 (1) (3) Total Recognized $ 2 $ 1 $ 2 $ — $ (2) $ (2)
Summary of Amounts Recognized in OCI	Amounts recognized in OCI for ARHI for the years ended December 31, 2020 and 2019, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2020 2019 2020 2019 (Millions) Net loss (gain) $ 21 $ 23 $ (7) $ (8)
Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans	PBO in excess of plan assets As of December 31, 2020 2019 (Millions) Projected benefit obligation $ 3,819 $ 3,669 Fair value of plan assets $ 3,092 $ 2,848 ABO in excess of plan assets As of December 31, 2020 2019 (Millions) Accumulated benefit obligation $ 3,629 $ 3,451 Fair value of plan assets $ 3,092 $ 2,848
Weighted Average Assumptions Used to Determine Benefit Obligations and Net periodic Benefit Cost	The weighted-average assumptions used to determine our benefit obligations as of December 31, 2020 and 2019 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2020 2019 2020 2019 Discount rate 2.34 % 3.01 % 2.19 % 2.99 % Rate of compensation increase 3.52 % 3.66 % 3.50 % 3.48 % Interest crediting rate 2.87 % 2.87 % N/A N/A The weighted-average assumptions used to determine our net periodic benefit cost for the years ended December 31, 2020, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2020 2019 2018 2020 2019 2018 Discount rate 3.01 % 3.98 % 3.68 % 2.99 % 3.97 % 3.67 % Expected long-term return on plan assets 7.30 % 7.30 % 7.30 % 5.09 % 5.08 % 5.08 % Rate of compensation increase 3.66 % 3.79 % 3.85 % 3.48 % 3.50 % 3.50 %
Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations	Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 Health care cost trend rate assumed for next year 5.25%/7.25% 6.75%/7.75% Rate to which cost trend rate is assumed to decline (ultimate trend rate) 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2029 / 2025 2029 / 2027
Expected Future Benefits Payments	Expected benefit payments as of December 31, 2020 consisted of: (Millions) Pension Benefits Postretirement Benefits 2021 $ 211 $ 31 2022 $ 224 $ 30 2023 $ 217 $ 29 2024 $ 219 $ 29 2025 $ 474 $ 49 2026 - 2030 $ 765 $ 100
Fair Values of Pension Benefits Plan Assets, by Asset Category	The fair values of pension benefits plan assets, by asset category, as of December 31, 2020, consisted of: As of December 31, 2020 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 120 $ — $ 120 $ — U.S. government securities 177 177 — — Common stocks 107 107 — — Registered investment companies 301 301 — — Corporate bonds 710 — 710 — Preferred stocks 1 1 — — Common collective trusts 1,018 — 1,018 — Other, principally annuity, fixed income 50 6 44 — $ 2,484 $ 592 $ 1,892 $ — Other investments measured at net asset value 608 Total $ 3,092 The fair values of pension benefits plan assets, by asset category, as of December 31, 2019, consisted of: As of December 31, 2019 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 42 $ — $ 42 $ — U.S. government securities 87 87 — — Registered investment companies 464 464 — — Corporate bonds 458 — 458 — Preferred stocks 1 1 — — Common collective trusts 572 — 572 — Other, principally annuity, fixed income 84 — 84 — $ 1,708 $ 552 $ 1,156 $ — Other investments measured at net asset value 1,140 Total $ 2,848
Fair Value of Other Postretirement Benefits Plan Assets, by Asset Category	The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2020 consisted of: As of December 31, 2020 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 6 $ — $ 6 $ — U.S. government securities 1 1 — — Registered investment companies 141 141 — — Corporate bonds 3 — 3 — Common collective trusts 4 — 4 — Other, principally annuity, fixed income 9 — 9 — $ 164 $ 142 $ 22 $ — Other investments measured at net asset value 3 Total $ 167 The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2019 consisted of: As of December 31, 2019 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 31 $ — $ 31 $ — Common stocks 16 16 — — Registered investment companies 98 98 — — Corporate bonds 2 — 2 — Other, principally annuity, fixed income 8 — 8 — Total $ 155 $ 114 $ 41 $ —

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated OCI (Loss) for the years ended December 31, 2020, 2019 and 2018 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2017 Adoption of new accounting standard 2018 Change As of December 31, 2018 Adoption of new accounting standard 2019 Change As of December 31, 2019 2020 Change As of December 31, 2020 (Millions) Change in revaluation of defined benefit plans, net of income tax expense (benefit) of $1 for 2018, $0 for 2019 and $0 for 2020 $ (14) $ — $ 3 $ (11) $ (2) $ 1 $ (12) $ — $ (12) Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) of $0 for 2018, $(1) for 2019 and $3 for 2020 (6) (1) 1 (6) — (1) (7) (13) (20) Unrealized (loss) gain on derivatives qualifying as cash flow hedges: Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $(7) for 2018, $(9) for 2019 and $(7) for 2020 30 — (21) 9 — (22) (13) (22) (35) Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $(7) for 2018, $3 for 2019 and $2 for 2020 (a) (56) — (8) (64) (10) 11 (63) 19 (44) Loss on derivatives qualifying as cash flow hedges (26) — (29) (55) (10) (11) (76) (3) (79) Accumulated Other Comprehensive Loss $ (46) $ (1) $ (25) $ (72) $ (12) $ (11) $ (95) $ (16) $ (111) (a) Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2020, 2019 and 2018, respectively, consisted of: Years Ended December 31, 2020 2019 2018 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 581 $ 667 $ 587 Denominator: Weighted average number of shares outstanding - basic 309,494,939 309,491,082 309,503,319 Weighted average number of shares outstanding - diluted 309,559,387 309,514,910 309,712,628 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 1.88 $ 2.16 $ 1.90 Earnings Per Common Share, Diluted $ 1.88 $ 2.16 $ 1.89

Grants, Government Incentives_2

Grants, Government Incentives and Deferred Income (Tables)	12 Months Ended
	Dec. 31, 2020
Other Liabilities Disclosure [Abstract]
Schedule of Changes in Deferred Income	The changes in deferred income as of December 31, 2020 and 2019 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2018 $ 1,367 $ 18 $ 1,385 Disposals (3) — (3) Derecognition due to sale (a) (38) — (38) Recognized in income (68) (2) (70) As of December 31, 2019 1,258 16 1,274 Disposals (2) — (2) Recognized in income (66) (2) (68) As of December 31, 2020 $ 1,190 $ 14 $ 1,204 (a) Grants no longer controlled by us due to the 2019 sale of a 50% interest in the Poseidon projects. See Note 22 for further information.

Other Financial Statements It_2

Other Financial Statements Items (Tables)	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Other Income and (Expense)	Other income (expense) for the years ended December 31, 2020, 2019 and 2018 consisted of: Years ended December 31, 2020 2019 2018 (Millions) Gain on sale of assets (a) $ 20 $ 148 $ 10 Allowance for funds used during construction 56 46 30 Carrying costs on regulatory assets 28 21 21 Non-service component of net periodic benefit cost (62) (79) (128) Other (24) (15) 1 Total Other Income (Expense) $ 18 $ 121 $ (66) (a) 2020 includes a $16 million gain from the Tatanka sale, 2019 includes a $134 million gain from the Poseidon sale and 2018 includes a $10 million gain from the Coyote Ridge sale (see Note 22).
Schedule of Accounts Receivable and Change in Allowance For Bad Debts	Accounts receivable and unbilled revenues, net as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Trade receivables and unbilled revenues $ 1,295 $ 1,151 Allowance for credit losses (108) (69) Total Accounts receivable and unbilled revenues, net $ 1,187 $ 1,082 The change in the allowance for credit losses as of December 31, 2020 and 2019 consisted of: (Millions) As of December 31, 2017 $ 64 Current period provision 74 Write-off as uncollectible (76) As of December 31, 2018 $ 62 Current period provision 92 Write-off as uncollectible (85) As of December 31, 2019 $ 69 Current period provision 83 Write-off as uncollectible (44) As of December 31, 2020 $ 108
Schedule of Prepayments and Other Current Assets	Prepayments and other current assets as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Prepaid other taxes $ 135 $ 123 Short-term investment (a) 300 — Broker margin and collateral accounts 30 33 Other pledged deposits 2 3 Prepaid expenses 41 34 Other 17 6 Total $ 525 $ 199
Schedule of Other Current Liabilities	Other current liabilities as of December 31, 2020 and 2019 consisted of: As of December 31, 2020 2019 (Millions) Advances received $ 141 $ 143 Accrued salaries 109 89 Short-term environmental provisions 49 40 Collateral deposits received 42 44 Pension and other postretirement 5 5 Finance leases 8 9 Other 14 6 Total $ 368 $ 336

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the year ended December 31, 2020 consisted of: For the year ended December 31, 2020 Networks Renewables Other(a) AVANGRID Consolidated (Millions) Revenue - external $ 5,187 $ 1,132 $ 1 $ 6,320 Revenue - intersegment 1 — (1) — Depreciation and amortization 592 394 1 987 Operating income 877 (16) 8 869 Earnings (losses) from equity method investments 10 (13) — (3) Interest expense, net of capitalization 234 7 75 316 Income tax expense (benefit) 120 (80) (11) 29 Capital expenditures 1,838 943 — 2,781 Adjusted net income 568 115 (58) 625 As of December 31, 2020 Property, plant and equipment 17,079 9,662 10 26,751 Equity method investments 134 534 — 668 Total assets $ 24,592 $ 12,867 $ 364 $ 37,823 (a) Includes Corporate and intersegment eliminations. Segment information as of and for the year ended December 31, 2019 consisted of: For the year ended December 31, 2019 Networks Renewables Other(a) AVANGRID Consolidated (Millions) Revenue - external $ 5,150 $ 1,184 $ 2 $ 6,336 Revenue - intersegment 14 — (14) — Depreciation and amortization 549 383 1 933 Operating income 890 93 15 998 Earnings (losses) from equity method investments 11 (8) — 3 Interest expense, net of capitalization 269 14 27 310 Income tax expense (benefit) 152 28 (11) 169 Capital expenditures 1,610 1,122 3 2,735 Adjusted net income 465 193 (17) 640 As of December 31, 2019 Property, plant and equipment 15,829 9,357 10 25,196 Equity method investments 139 506 — 645 Total assets $ 23,239 $ 13,152 $ (1,997) $ 34,394 (a) Includes Corporate and intersegment eliminations. Segment information for the year ended December 31, 2018 consisted of: For the year ended December 31, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 5,304 $ 1,136 $ 37 $ 6,477 Revenue - intersegment 6 2 (8) — Loss from assets held for sale — — 16 16 Depreciation and amortization 503 352 — 855 Operating income 968 132 16 1,116 Earnings (losses) from equity method investments 13 (3) — 10 Interest expense, net of capitalization 260 33 10 303 Income tax expense (benefit) 167 (32) 32 167 Capital expenditures 1,370 407 — 1,777 Adjusted net income $ 481 $ 182 $ 13 $ 676 (a) Includes Corporate, Gas and intersegment eliminations.
Schedule of Reconciliation of Consolidated EBITDA to Consolidated Net Income	Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the years ended December 31, 2020, 2019 and 2018 is as follows: Years Ended December 31, 2020 2019 2018 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 625 $ 640 $ 676 Adjustments: Restructuring charges (1) (6) (6) (4) Mark-to-market adjustments - Renewables (2) (5) 76 (25) Loss from held for sale measurement (3) — — (16) Impact of the Tax Act (4) — — (46) Accelerated depreciation from repowering (5) (9) (33) (3) Impact of COVID-19 (6) (29) — — Merger costs (7) (6) — — Legal settlement - Gas storage (8) (5) — — Income tax impact of adjustments 16 (10) (6) Gas Storage, net of tax (8) — — 11 Net Income Attributable to Avangrid, Inc. $ 581 $ 667 $ 587 (1) Restructuring and severance related charges relate to costs resulted from restructuring actions involving initial targeted voluntary workforce reductions and related costs in our plan to vacate a lease, predominantly within the Networks segment and costs to implement an initiative to mitigate costs and achieve sustainable growth (See Note 27 - Restructuring and Severance Related Expenses – for further details). (2) Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas. (3) Represents loss from measurement of assets and liabilities held for sale in connection with the committed plan to sell the gas trading and storage businesses. (4) Represents the impact from measurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. (5) Represents the amount of accelerated depreciation derived from repowering wind farms in Renewables. (6) Represents costs incurred in connection with the COVID-19 pandemic. (7) Pre-merger costs incurred. (8) Removal of the impact from Gas activity in the reconciliation to AVANGRID Net Income.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Schedule of Related Party Transactions and Balances	Related party transactions for the years ended December 31, 2020, 2019 and 2018, respectively, consisted of: Years Ended December 31, 2020 2019 2018 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ 1 $ (43) $ 1 $ (42) $ 1 $ (38) Iberdrola Renovables Energia, S.L. $ — $ (9) $ — $ (9) $ — $ (14) Iberdrola Financiación, S.A. $ — $ (7) $ — $ (3) $ — $ (3) Vineyard Wind $ 9 $ — $ 13 $ — $ 3 $ — Iberdrola Solutions $ 2 $ — $ 1 $ — $ — $ — Iberdrola Energia Monterrey, S.A. de C.V. $ — $ — $ — $ — $ 3 $ — Iberdrola Canada Energy Services, Ltd $ — $ — $ — $ — $ — $ (5) Other $ — $ — $ 1 $ (3) $ 2 $ (5) Related party balances as of December 31, 2020 and 2019, respectively, consisted of: As of December 31, 2020 2019 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ 2 $ (43) $ 1 $ (42) Iberdrola Financiacion $ — $ (6) $ — $ (3) Siemens-Gamesa (a) $ — $ — $ — $ (18) Vineyard Wind $ 4 $ — $ 5 $ — Iberdrola Solutions $ 5 $ — $ — $ — Other $ 1 $ (1) $ 4 $ (1) (a) After Iberdrola's sale of its interest of Siemens-Gamesa in February 2020, transactions with Siemens-Gamesa are no longer considered related party.

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Schedule of Nonvested PSUs	A summary of the status of the AVANGRID's nonvested PSUs and RSUs as of December 31, 2020, and changes during the fiscal year ended December 31, 2020, is presented below: Number of PSUs and RSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2019 1,274,280 $ 32.83 Granted 6,691 $ 49.20 Forfeited (997,088) $ 31.80 Vested (141,716) $ 41.44 Nonvested Balance – December 31, 2020 142,167 $ 32.42

Restructuring and Severance R_2

Restructuring and Severance Related Expenses (Tables)	12 Months Ended
	Dec. 31, 2020
Restructuring and Related Activities [Abstract]
Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities and Other Liabilities	For the year ended December 31, 2020, the severance and lease restructuring charges reserves, which are recorded in “Other current liabilities” and “Other liabilities”, consisted of: For the Year Ended December 31, 2020 (Millions) Beginning Balance $ 5 Restructuring and severance related expenses 2 Payments (4) Ending Balance $ 3

Background and Nature of Oper_2

Background and Nature of Operations (Details) - USD ($)	Oct. 20, 2020	Dec. 31, 2020
NM Green Holdings, Inc.
Noncontrolling Interest [Line Items]
Merger agreement, share price (in dollars per share)	$ 50.30
Merger agreement term, ownership percentage benchmark	15.00%
Merger agreement, termination rights term, extension period	3 months
Merger agreement, termination rights term, termination fees	$ 130,000,000
Merger agreement, termination rights term, termination fees as remedy	184,000,000
Merger agreement, termination rights term, termination fees, out-of-pocket fees and expenses reimbursable limit (up to)	$ 10,000,000
AVANGRID | Iberdrola S.A.
Noncontrolling Interest [Line Items]
Parent company, ownership percentage		81.50%

Basis of Presentation - Effects

Basis of Presentation - Effects To Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Decrease in retained earnings	$ (1,666)	$ (1,634)
Assets
Total Property, Plant and Equipment ($1,637 and $787 related to VIEs, respectively)	26,751	25,196
Total Assets	37,823	34,394
Liabilities
Other current liabilities	368	336
Total Current Liabilities	3,069	3,589
Deferred income taxes	1,919	1,837
Total Other Non-current Liabilities	5,313	5,269
Total Non-current Liabilities	18,928	15,266
Total Liabilities	21,997	18,855
Equity
Retained earnings	1,666	1,634
Total Stockholders’ Equity	15,209	15,190
Total Equity	15,826	15,539	$ 15,389	$ 15,090
Total Liabilities and Equity	$ 37,823	34,394
As Reported
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Decrease in retained earnings		(1,681)
Assets
Total Property, Plant and Equipment ($1,637 and $787 related to VIEs, respectively)		25,218
Total Assets		34,416
Liabilities
Other current liabilities		334
Total Current Liabilities		3,587
Deferred income taxes		1,814
Total Other Non-current Liabilities		5,246
Total Non-current Liabilities		15,243
Total Liabilities		18,830
Equity
Retained earnings		1,681
Total Stockholders’ Equity		15,237
Total Equity		15,586
Total Liabilities and Equity		34,416
Correction
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Decrease in retained earnings		47	6
Assets
Total Property, Plant and Equipment ($1,637 and $787 related to VIEs, respectively)		(22)
Total Assets		(22)
Liabilities
Other current liabilities		2
Total Current Liabilities		2
Deferred income taxes		23
Total Other Non-current Liabilities		23
Total Non-current Liabilities		23
Total Liabilities		25
Equity
Retained earnings		(47)	$ (6)
Total Stockholders’ Equity		(47)
Total Equity		(47)
Total Liabilities and Equity		$ (22)

Basis of Presentation - Effec_2

Basis of Presentation - Effects To Statements Of Income (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Operating Revenues	$ 6,320	$ 6,336	$ 6,477
Operations and maintenance	2,466	2,305	2,258
Depreciation and amortization	987	933	855
Total Operating Expenses	5,451	5,338	5,361
Operating Income	869	998	1,116
Other income (expense)	18	121	(66)
Interest expense	(316)	(310)	(303)
Income Before Income Tax	568	812	757
Income tax expense	29	169	167
Net Income	539	643	590
Net income attributable to AVANGRID	$ 581	$ 667	$ 587
Earnings Per Common Share, Basic (in dollars per share)	$ 1.88	$ 2.16	$ 1.90
Earnings Per Common Share, Diluted (in dollars per share)	$ 1.88	$ 2.16	$ 1.89
As Reported
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Operating Revenues		$ 6,338	$ 6,478
Operations and maintenance		2,301	2,248
Depreciation and amortization		934
Total Operating Expenses		5,335	5,351
Operating Income		1,003	1,127
Other income (expense)		119
Interest expense		(306)
Income Before Income Tax		819	768
Income tax expense		143	170
Net Income		676	598
Net income attributable to AVANGRID		$ 700	$ 595
Earnings Per Common Share, Basic (in dollars per share)		$ 2.26	$ 1.92
Earnings Per Common Share, Diluted (in dollars per share)		$ 2.26	$ 1.92
Correction
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Operating Revenues		$ (2)	$ (1)
Operations and maintenance		4	10
Depreciation and amortization		(1)
Total Operating Expenses		3	10
Operating Income		(5)	(11)
Other income (expense)		2
Interest expense		(4)
Income Before Income Tax		(7)	(11)
Income tax expense		26	(3)
Net Income		(33)	(8)
Net income attributable to AVANGRID		$ (33)	$ (8)
Earnings Per Common Share, Basic (in dollars per share)		$ (0.10)	$ (0.02)
Earnings Per Common Share, Diluted (in dollars per share)		$ (0.10)	$ (0.03)

Basis of Presentation - Effec_3

Basis of Presentation - Effects To Statements Of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Income	$ 539	$ 643	$ 590
Depreciation and amortization	987	933	855
Deferred taxes	17	164	148
Current liabilities	160	(2)	99
Net Cash Provided by Operating Activities	1,288	1,588	1,781
Capital expenditures	(2,781)	(2,735)	(1,777)
Net Cash Used in Investing Activities	(2,858)	(2,708)	(1,554)
Cash paid for interest, net of amounts capitalized	$ 278	270	224
As Reported
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Income		676	598
Depreciation and amortization		934	855
Deferred taxes		138	151
Current liabilities		(5)	98
Net Cash Provided by Operating Activities		1,593	1,791
Capital expenditures		(2,740)	(1,787)
Net Cash Used in Investing Activities		(2,713)	(1,564)
Cash paid for interest, net of amounts capitalized		266	224
Correction
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Income		(33)	(8)
Depreciation and amortization		(1)	0
Deferred taxes		26	(3)
Current liabilities		3	1
Net Cash Provided by Operating Activities		(5)	(10)
Capital expenditures		5	10
Net Cash Used in Investing Activities		5	10
Cash paid for interest, net of amounts capitalized		$ 4	$ 0

Summary of Significant Accoun_4

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Jan. 01, 2020	Dec. 31, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Composite rate	2.90%	2.90%
Average remaining service period	10 years
Expected return on plan assets, period	5 years
Cumulative adjustment to retained earnings	$ (15,826)	$ (15,539)		$ (15,389)	$ (15,090)
Unionized Employees Concentration Risk | Employees covered by a collective bargaining agreement
Finite-Lived Intangible Assets [Line Items]
Percentage of employees covered by collective bargaining agreement	48.80%
Unionized Employees Concentration Risk | Agreements which will expire within the coming year
Finite-Lived Intangible Assets [Line Items]
Percentage of employees covered by collective bargaining agreement	16.00%
Retained Earnings
Finite-Lived Intangible Assets [Line Items]
Cumulative adjustment to retained earnings	$ (1,666)	(1,634)		(1,514)	(1,469)
Cumulative Effect, Period of Adoption, Adjustment
Finite-Lived Intangible Assets [Line Items]
Cumulative adjustment to retained earnings		1		1	(136)
Cumulative Effect, Period of Adoption, Adjustment | Retained Earnings
Finite-Lived Intangible Assets [Line Items]
Cumulative adjustment to retained earnings		$ 1	$ 1	$ (11)	$ 3
Min.
Finite-Lived Intangible Assets [Line Items]
Useful economic life	4 years
Max.
Finite-Lived Intangible Assets [Line Items]
Useful economic life	40 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2020
Plant | Solar power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Min. | Plant | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	35 years
Min. | Plant | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	45 years
Min. | Plant | Wind power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Min. | Plant | Transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	40 years
Min. | Plant | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	15 years
Min. | Equipment | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	7 years
Min. | Equipment | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	4 years
Min. | Other | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	30 years
Min. | Other | Operations offices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	5 years
Max. | Plant | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	55 years
Max. | Plant | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	90 years
Max. | Plant | Wind power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	40 years
Max. | Plant | Transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years
Max. | Plant | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	80 years
Max. | Equipment | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	60 years
Max. | Equipment | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Max. | Other | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	82 years
Max. | Other | Operations offices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years

Revenue - Additional Informatio

Revenue - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Contract assets, noncurrent	$ 9	$ 12
Contract liabilities, current	9	10
Contract liabilities, revenue recognized	21	21	$ 13
Accounts receivable related to contracts with customers	1,151	1,050
Unbilled contracts receivable	$ 341	$ 345
Min. | Transmission Congestion Contracts
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	6 months
Max. | Transmission Congestion Contracts
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	2 years
Networks
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	1 year
Renewables
Disaggregation of Revenue [Line Items]
Capitalized contract cost amortization term	15 years

Revenue - Schedule of Revenues

Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 5,992	$ 5,963	$ 5,823
Leasing revenue	6	6	384
Derivative revenue	136	244	134
Alternative revenue programs	157	75	80
Other revenue	29	48	56
Total operating revenues	6,320	6,336	6,477
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	(12)	19
Leasing revenue	0	0	0
Derivative revenue	0	0	10
Alternative revenue programs	0	0	0
Other revenue	0	0	0
Total operating revenues	0	(12)	29
Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	3,642	3,485	3,641
Regulated operations – electricity | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,311	1,479	1,473
Regulated operations – natural gas | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	822	803	636
Nonregulated operations – wind | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	19	26	17
Nonregulated operations – solar | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	39	29	47
Nonregulated operations – thermal | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – gas storage
Segment Reporting Information [Line Items]
Revenue from contracts with customers			10
Nonregulated operations – gas storage | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers			10
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	159	141	(1)
Other | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	(12)	9
Networks
Segment Reporting Information [Line Items]
Revenue from contracts with customers	5,011	5,055	5,172
Leasing revenue	6	6	38
Derivative revenue	0	0	0
Alternative revenue programs	157	75	80
Other revenue	14	28	20
Total operating revenues	5,188	5,164	5,310
Networks | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	3,642	3,485	3,641
Networks | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,311	1,479	1,473
Networks | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Nonregulated operations – gas storage
Segment Reporting Information [Line Items]
Revenue from contracts with customers			0
Networks | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	58	91	58
Renewables
Segment Reporting Information [Line Items]
Revenue from contracts with customers	981	920	632
Leasing revenue	0	0	346
Derivative revenue	136	244	124
Alternative revenue programs	0	0	0
Other revenue	15	20	36
Total operating revenues	1,132	1,184	1,138
Renewables | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Renewables | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Renewables | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	822	803	636
Renewables | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	19	26	17
Renewables | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	39	29	47
Renewables | Nonregulated operations – gas storage
Segment Reporting Information [Line Items]
Revenue from contracts with customers			0
Renewables | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 101	$ 62	$ (68)

Revenue - Schedule of Aggregate

Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details) $ in Millions	Dec. 31, 2020USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 265
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	4
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	79
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	182
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	72
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | 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]: 2021-01-01 | 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	$ 31
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | 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	$ 40
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 48
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	$ 1
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	$ 23
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	$ 24
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	$ 30
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	$ 13
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	$ 16
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	$ 19
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	$ 4
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	$ 14
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	$ 3
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	$ 12
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	$ 80
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
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	$ 5
Remaining performance obligation, period
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	$ 75
Remaining performance obligation, period

Industry Regulation - Additiona

Industry Regulation - Additional Information (Details) MWh in Millions

Dec. 31, 2020USD ($)project

Sep. 23, 2020project

Feb. 19, 2020USD ($)

Jan. 21, 2020

Dec. 09, 2019USD ($)

May 20, 2019

Jan. 18, 2019

Dec. 28, 2018MWhproject

Sep. 10, 2018USD ($)

Jan. 01, 2017

Mar. 31, 2010USD ($)MW

Aug. 31, 2019MW

Oct. 31, 2018agreementMW

Dec. 31, 2017

Mar. 31, 2017orderproject

Dec. 31, 2016

Dec. 31, 2020USD ($)companyproject

Apr. 30, 2019

Jun. 22, 2020

Apr. 27, 2020USD ($)

Dec. 31, 2019USD ($)

Jan. 31, 2018USD ($)

Public Utilities, General Disclosures [Line Items]

Number of networks supply companies | company

8

Approved return on equity

9.88%

Equity ratio

3.00%

54.00%

50.00%

3.00%

Percentage of standard service customers with wholesale power supply agreements in place for the second half of 2021

70.00%

Percentage of standard service customers with wholesale power supply agreements in place for the first half of 2022

20.00%

Public utilities regulatory authority distribution rate

9.70%

Number of REV related orders issued | order

3

Number of energy storage projects | project

2

Regulatory assets

$ 2,882,000,000

$ 2,882,000,000

$ 2,861,000,000

$ 11,000,000

Number of average months used to set rate

13 months

Restricted net assets

5,408,000,000

$ 5,408,000,000

Rate plan modification, overall bill impact limit, percent

2.00%

Purchase obligation per year

$ 2,125,000,000

$ 2,125,000,000

DEEP

Public Utilities, General Disclosures [Line Items]

PPA capacity (in MWH) | MWh

12

Maine Public Utilities Commission (MPUC)

Public Utilities, General Disclosures [Line Items]

Number of projects | project

14

PURA

Public Utilities, General Disclosures [Line Items]

Equity ratio

50.00%

Percentage of return on equity (ROE)

9.10%

9.30%

New distribution rate schedule, period

3 years

Public utilities regulatory authority distribution rate

50.00%

Equity ratio, year one

54.00%

54.00%

Equity ratio, year two

54.50%

54.50%

Equity ratio, year three

55.00%

55.00%

Power Tax

Public Utilities, General Disclosures [Line Items]

Depreciation amortization period

32 years 6 months

Depreciation amortization period

32 years 6 months

Storm costs

Public Utilities, General Disclosures [Line Items]

Regulatory assets

$ 451,000,000

$ 451,000,000

272,000,000

Federal tax depreciation normalization adjustment

Public Utilities, General Disclosures [Line Items]

Regulatory assets

148,000,000

148,000,000

$ 153,000,000

Central Maine Power

Public Utilities, General Disclosures [Line Items]

Distribution revenue requirement

$ 17,000,000

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%

Customer service performance period

18 months

Benchmark amount of metering, billing and customer service practices audit costs (less than)

$ 1,000,000

SCG

Public Utilities, General Disclosures [Line Items]

Equity ratio

52.00%

Percentage of return on equity (ROE)

9.25%

NYDPS

Public Utilities, General Disclosures [Line Items]

Equity ratio for earnings sharing

48.00%

Percentage of return on equity (ROE)

8.80%

United Illuminating Company (UI)

Public Utilities, General Disclosures [Line Items]

Maximum amount of commitment to purchase renewable energy credits (recs) from new facilities behind distribution customer meters

200,000,000

$ 200,000,000

Proposed off shore wind capacity (in MW) | MW

50

Period of purchase commitment

21 years

Solicitation period

6 years

Maximum annual commitment level obligation after year six

14,000,000

$ 14,000,000

Additional maximum annual commitment

$ 64,000,000

$ 64,000,000

Number of power purchase agreements | agreement

5

Number of projects | project

11

Vineyard Wind

Public Utilities, General Disclosures [Line Items]

Proposed off shore wind capacity (in MW) | MW

804

CMP

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

20 years

Wind farm capacity (in MW) | MW

60

Purchase obligation per year

$ 7,000,000

CMP | Dirigo Solar, LLC

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

Purchase obligation per year

$ 4,000,000

CMP | Maine Aqua Ventus I GP LLC

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

Purchase obligation per year

$ 12,000,000

CMP | Maine Public Utilities Commission (MPUC)

Public Utilities, General Disclosures [Line Items]

Number of projects | project

13

Number of projects executed | project

5

5

NYSEG Electric

Public Utilities, General Disclosures [Line Items]

Approved return on equity

9.00%

Equity ratio

48.00%

48.00%

Equity ratio for earnings sharing

50.00%

50.00%

Recovery of deferred storm costs

$ 262,000,000

NYSEG Electric | Storm costs, ten year recovery

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

123,000,000

NYSEG Electric | Storm costs, five year recovery

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

139,000,000

NYSEG Electric | Deferred Storm Cost Amortization 1 Year

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

$ 21,000,000

NYSEG Electric | Storm costs

Public Utilities, General Disclosures [Line Items]

Depreciation amortization period

10 years

Depreciation amortization period

10 years

NYSEG Electric | Regulatory Items Other Than Storm Costs

Public Utilities, General Disclosures [Line Items]

Depreciation amortization period

5 years

Depreciation amortization period

5 years

NYSEG Gas

Public Utilities, General Disclosures [Line Items]

Percentage of earnings customers received

50.00%

Percentage of return on equity (ROE)

9.75%

RG&E Electric

Public Utilities, General Disclosures [Line Items]

Percentage of earnings customers received

75.00%

Percentage of return on equity (ROE)

10.25%

RG&E Electric | Deferred Storm Cost Amortization 1 Year

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

$ 3,000,000

RG&E Gas

Public Utilities, General Disclosures [Line Items]

Percentage of earnings customers received

90.00%

Percentage of return on equity (ROE)

10.75%

Industry Regulation - Rate Incr

Industry Regulation - Rate Increases and Delivery Rate Percentages (Details) - USD ($) $ in Millions	Jun. 22, 2020	Jun. 15, 2016
NYSEG Electric | Year 1
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 34
Delivery Rate Increase	4.60%
NYSEG Electric | Year 2
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 46
Delivery Rate Increase	5.90%
NYSEG Electric | Year 3
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 36	$ 30
Delivery Rate Increase	4.20%	4.10%
NYSEG Gas | Year 1
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 0
Delivery Rate Increase	0.00%
NYSEG Gas | Year 2
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 2
Delivery Rate Increase	0.80%
NYSEG Gas | Year 3
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 3	$ 15
Delivery Rate Increase	1.60%	7.30%
RG&E Electric | Year 1
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 17
Delivery Rate Increase	3.80%
RG&E Electric | Year 2
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 14
Delivery Rate Increase	3.20%
RG&E Electric | Year 3
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 16	$ 26
Delivery Rate Increase	3.30%	5.70%
RG&E Gas | Year 1
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 0
Delivery Rate Increase	0.00%
RG&E Gas | Year 2
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 0
Delivery Rate Increase	0.00%
RG&E Gas | Year 3
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 2	$ 10
Delivery Rate Increase	1.30%	5.20%

Industry Regulation - Rate In_2

Industry Regulation - Rate Increases (Details) - USD ($) $ in Millions	Jun. 22, 2020	Jun. 15, 2016
NYSEG Electric | Year 1
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 34
Electric And Gas Delivery Rate Increase	4.60%
NYSEG Electric | Year 2
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 46
Electric And Gas Delivery Rate Increase	5.90%
NYSEG Electric | Year 3
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 36	$ 30
Electric And Gas Delivery Rate Increase	4.20%	4.10%
NYSEG Gas | Year 1
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 0
Electric And Gas Delivery Rate Increase	0.00%
NYSEG Gas | Year 2
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 2
Electric And Gas Delivery Rate Increase	0.80%
NYSEG Gas | Year 3
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 3	$ 15
Electric And Gas Delivery Rate Increase	1.60%	7.30%
RG&E Electric | Year 1
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 17
Electric And Gas Delivery Rate Increase	3.80%
RG&E Electric | Year 2
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 14
Electric And Gas Delivery Rate Increase	3.20%
RG&E Electric | Year 3
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 16	$ 26
Electric And Gas Delivery Rate Increase	3.30%	5.70%
RG&E Gas | Year 1
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 0
Electric And Gas Delivery Rate Increase	0.00%
RG&E Gas | Year 2
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 0
Electric And Gas Delivery Rate Increase	0.00%
RG&E Gas | Year 3
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 2	$ 10
Electric And Gas Delivery Rate Increase	1.30%	5.20%

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities - Regulatory Assets Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)
Regulated Operations [Abstract]
Unrecorded regulatory assets	$ 1,484
Regulatory Assets [Line Items]
Unfunded future income tax expense collection period	46 years
Central Maine Power
Regulatory Assets [Line Items]
Deferred income tax recovery period	32 years 6 months

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities - Schedule of Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Jan. 31, 2018
Regulatory Assets [Line Items]
Regulatory Assets, Total	$ 2,882	$ 2,861	$ 11
Regulatory Assets, Current	310	294
Regulatory Assets, Noncurrent, Including Deferred Income Taxes Regulatory	2,572	2,567
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Regulatory Assets, Total	105	125
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Regulatory Assets, Total	927	1,061
Storm costs
Regulatory Assets [Line Items]
Regulatory Assets, Total	451	272
Rate adjustment mechanism
Regulatory Assets [Line Items]
Regulatory Assets, Total	33	79
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Regulatory Assets, Total	58	19
Transmission revenue reconciliation mechanism
Regulatory Assets [Line Items]
Regulatory Assets, Total	31	5
Contracts for differences
Regulatory Assets [Line Items]
Regulatory Assets, Total	86	92
Hardship programs
Regulatory Assets [Line Items]
Regulatory Assets, Total	20	29
Plant decommissioning
Regulatory Assets [Line Items]
Regulatory Assets, Total	3	5
Deferred purchased gas
Regulatory Assets [Line Items]
Regulatory Assets, Total	30	25
Deferred transmission expense
Regulatory Assets [Line Items]
Regulatory Assets, Total	26	11
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Regulatory Assets, Total	247	277
Debt premium
Regulatory Assets [Line Items]
Regulatory Assets, Total	83	97
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Regulatory Assets, Total	26	29
Unfunded future income taxes
Regulatory Assets [Line Items]
Regulatory Assets, Total	373	399
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Regulatory Assets, Total	148	153
Asset retirement obligation
Regulatory Assets [Line Items]
Regulatory Assets, Total	21	17
Deferred meter replacement costs
Regulatory Assets [Line Items]
Regulatory Assets, Total	33	27
COVID-19 cost recovery
Regulatory Assets [Line Items]
Regulatory Assets, Total	1	0
Other
Regulatory Assets [Line Items]
Regulatory Assets, Total	$ 180	$ 139

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 3,411	$ 3,523
Less: current portion	274	242
Regulatory liabilities	3,137	3,281
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	58	72
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	3	11
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	59	80
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	34	49
Carrying costs on deferred income tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	11	15
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,435	1,548
Rate change levelization
Regulatory Liabilities [Line Items]
Total regulatory liabilities	55	10
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	9	17
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,184	1,173
Asset sale gain account
Regulatory Liabilities [Line Items]
Total regulatory liabilities	7	10
Economic development
Regulatory Liabilities [Line Items]
Total regulatory liabilities	28	27
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	30	37
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Total regulatory liabilities	10	14
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	31	17
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	20	23
Debt rate reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	63	67
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Total regulatory liabilities	33	32
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Total regulatory liabilities	22	23
Merger-related rate credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	14	16
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	25	13
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	14
Earnings sharing provisions
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	28
Middletown/Norwalk local transmission network service collections
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	18
Low income programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities	28	33
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	14	16
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Total regulatory liabilities	9	11
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 176	$ 149

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities - Regulatory Liabilities Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
UIL Holdings
Regulatory Liabilities [Line Items]
Business combination merger related rate credits	$ 2	$ 2
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Carrying costs on deferred income tax
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Rate change levelization
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Positive benefit adjustment | Min.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Positive benefit adjustment | Max.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Theoretical reserve flow thru impact | Min.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Theoretical reserve flow thru impact | Max.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Deferred property tax
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Net plant reconciliation
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
NYSEG and RG&E | Economic development
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
NYSEG | Asset sale gain account
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
RG&E | Asset sale gain account
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	2 years

Goodwill and Intangible asset_2

Goodwill and Intangible assets - Schedule of Goodwill by Reportable Segment (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Goodwill [Line Items]
Goodwill	$ 3,119	$ 3,119
Networks
Goodwill [Line Items]
Goodwill	2,747	2,747
Renewables
Goodwill [Line Items]
Goodwill	$ 372	$ 372

Goodwill and Intangible asset_3

Goodwill and Intangible assets - Additional Information (Details)	Dec. 16, 2015USD ($)	Dec. 31, 2020USD ($)reportingUnit	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2002USD ($)	Dec. 31, 2000USD ($)
Goodwill [Line Items]
Goodwill reduction		$ 8,000,000
Impairment of goodwill		0	$ 0
Amortization expense		$ 14,000,000	$ 15,000,000	$ 15,000,000
Maine Reporting Unit
Goodwill [Line Items]
Goodwill						$ 325,000,000
New York Reporting Unit
Goodwill [Line Items]
Goodwill					$ 654,000,000
UIL Reporting Unit
Goodwill [Line Items]
Goodwill	$ 1,768,000,000
Networks
Goodwill [Line Items]
Number of reporting units | reportingUnit		3
Poseidon Project
Goodwill [Line Items]
Ownership percentage sold		50.00%	50.00%

Goodwill and Intangible asset_4

Goodwill and Intangible assets - Summary of Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 624	$ 619
Accumulated Amortization	(319)	(305)
Net Carrying Amount	305	314
Wind development
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	593	591
Accumulated Amortization	(290)	(289)
Net Carrying Amount	303	302
Other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	31	28
Accumulated Amortization	(29)	(16)
Net Carrying Amount	$ 2	$ 12

Goodwill and Intangible asset_5

Goodwill and Intangible assets - Schedule of Amortization Expense (Details) $ in Millions	Dec. 31, 2020USD ($)
Year ending December 31,
2021	$ 14
2022	13
2023	12
2024	12
2025	$ 12

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 34,142	$ 32,096
Total accumulated depreciation	(9,799)	(9,058)
Total Net Property, Plant and Equipment in Service	24,343	23,038
Construction work in progress	2,408	2,158
Total Property, Plant and Equipment	26,751	25,196
Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	29,218	27,452
Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	4,650	4,386
Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	274	258
Regulated
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	21,001	19,465
Total accumulated depreciation	(5,363)	(4,968)
Total Net Property, Plant and Equipment in Service	15,638	14,497
Construction work in progress	1,384	1,271
Total Property, Plant and Equipment	17,022	15,768
Regulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	16,364	15,092
Regulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	4,637	4,373
Regulated | Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	0	0
Nonregulated
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	13,141	12,631
Total accumulated depreciation	(4,436)	(4,090)
Total Net Property, Plant and Equipment in Service	8,705	8,541
Construction work in progress	1,024	887
Total Property, Plant and Equipment	9,729	9,428
Nonregulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	12,854	12,360
Nonregulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	13	13
Nonregulated | Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 274	$ 258

Property, Plant and Equipment_2

Property, Plant and Equipment - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Interest costs capitalized	$ 51	$ 51	$ 26
Accrued liabilities for property, plant and equipment additions	285	357	154
Tangible asset impairment charges	7	11	0
Depreciation	$ 973	$ 918	$ 840

Asset retirement obligations -

Asset retirement obligations - Reconciliation of ARO (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 190	$ 217
Liabilities settled during the year	(2)	(5)
Liabilities incurred during the year	9	6
Accretion expense	11	12
Revisions in estimated cash flows	2	(40)
Ending Balance	$ 210	$ 190

Asset retirement obligations _2

Asset retirement obligations - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, restricted cash	$ 3	$ 2

Debt - Schedule of Long-term De

Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Unamortized debt issuance costs and discount	$ (47)	$ (38)
Total Debt	7,791	7,446
Less: debt due within one year, included in current liabilities	313	730
Total Non-current Debt	7,478	6,716
First mortgage bonds - fixed
Debt Instrument [Line Items]
Long-term debt	2,575	$ 2,218
Bond pledged as collateral	$ 7,483
First mortgage bonds - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	1.85%	3.07%
First mortgage bonds - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	8.00%	8.00%
Unsecured pollution control notes - fixed
Debt Instrument [Line Items]
Long-term debt	$ 478	$ 538
Unsecured pollution control notes - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	1.40%	2.00%
Unsecured pollution control notes - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	3.50%	3.50%
Term loan - variable
Debt Instrument [Line Items]
Long-term debt	$ 0	$ 500
Term loan - variable | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate		2.40%
Other various non-current debt - fixed
Debt Instrument [Line Items]
Long-term debt	$ 4,785	$ 4,228
Other various non-current debt - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	1.95%	2.80%
Other various non-current debt - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	7.80%	10.48%

Debt - Additional Information (

Debt - Additional Information (Details) - USD ($)	Dec. 14, 2020	Jun. 29, 2020	Dec. 31, 2020	Jun. 28, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Estimated fair value of debt			$ 12,166,000,000		$ 8,168,000,000
Notes payable			307,000,000		560,000,000
Commercial paper			309,000,000		562,000,000
AVANGRID
Debt Instrument [Line Items]
Notes payable			308,000,000		$ 561,000,000
Commercial Paper [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 2,000,000,000
weighted-average interest rate			0.32%		2.07%
Line of Credit
Debt Instrument [Line Items]
Credit facility remaining borrowing capacity			$ 2,691,000,000		$ 1,938,000,000
Subordinated Debt | Iberdrola Loan
Debt Instrument [Line Items]
Debt prepayment term, period of notice	5 days
Subordinated Debt | Iberdrola Loan | AVANGRID
Debt Instrument [Line Items]
Debt instrument principal amount	$ 3,000,000,000
Debt instrument, interest rate	0.20%
Monthly floating interest rate	0.01%
Debt prepayment term, period of notice	5 days
Subordinated Debt | Max. | Iberdrola Loan | AVANGRID
Debt Instrument [Line Items]
Debt instrument, interest rate	0.25%
Revolving Credit Facility | 2020 Credit Facility
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity		$ 500,000,000
Credit facility initial fees range			0.20%
Extension term		1 year
Extension cost, percentage		0.75%
Debt Instrument, Extension Period		1 year
Revolving Credit Facility | Min. | 2020 Credit Facility
Debt Instrument [Line Items]
Credit facility initial fees range		0.15%
Revolving Credit Facility | Max. | 2020 Credit Facility
Debt Instrument [Line Items]
Credit facility initial fees range		0.30%
Revolving Credit Facility | Line of Credit
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 2,500,000,000
Revolving Credit Facility | Line of Credit | Iberdrola Financiacion S A U
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 500,000,000
Credit facility initial fees range			0.105%
Credit facility amount drawn			$ 0		$ 0
AVANGRID Credit Facility | Min.
Debt Instrument [Line Items]
Credit facility initial fees range			0.10%
AVANGRID Credit Facility | Max.
Debt Instrument [Line Items]
Credit facility initial fees range			0.175%
AVANGRID Credit Facility | Line of Credit
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity		$ 1,500,000,000		$ 2,000,000,000
Cash and Cash Equivalents | Subordinated Debt | Iberdrola Loan
Debt Instrument [Line Items]
Proceeds from short-term debt			$ 1,438,000,000
Prepaid Expenses and Other Current Assets | Subordinated Debt | Iberdrola Loan
Debt Instrument [Line Items]
Proceeds from short-term debt			$ 300,000,000

Debt - Other 2020 Long-Term Deb

Debt - Other 2020 Long-Term Debt Issuances (Details) - USD ($) $ in Millions	Dec. 15, 2020	Dec. 01, 2020	Nov. 23, 2020	Sep. 25, 2020	Sep. 01, 2020	May 01, 2020	Apr. 09, 2020
Senior Notes | AVANGRID
Debt Instrument [Line Items]
Debt instrument, interest rate							3.20%
Senior Notes | NYSEG
Debt Instrument [Line Items]
Debt instrument, interest rate				1.95%
Senior Notes | BGC
Debt Instrument [Line Items]
Debt instrument, interest rate					3.68%
Senior Notes | RG&E
Debt Instrument [Line Items]
Debt instrument, interest rate			1.85%
Senior Notes | UI
Debt Instrument [Line Items]
Debt instrument, interest rate		2.02%
Senior Notes | CMP
Debt Instrument [Line Items]
Debt instrument, interest rate	1.87%
Senior Notes | CNG
Debt Instrument [Line Items]
Debt instrument, interest rate	2.02%
Senior Notes | SCG
Debt Instrument [Line Items]
Debt instrument, interest rate	1.87%
Unsecured Debt | AVANGRID
Debt Instrument [Line Items]
Debt instrument principal amount							$ 750
Unsecured Debt | NYSEG
Debt Instrument [Line Items]
Debt instrument principal amount				$ 200
Unsecured Debt | BGC
Debt Instrument [Line Items]
Debt instrument principal amount					$ 25
Unsecured Debt | UI
Debt Instrument [Line Items]
Debt instrument principal amount		$ 75
Unsecured Debt | CNG
Debt Instrument [Line Items]
Debt instrument principal amount	$ 30
Pollution Control Bonds | NYSEG
Debt Instrument [Line Items]
Debt instrument principal amount						$ 200
Pollution Control Bonds | NYSEG | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate						1.40%
Pollution Control Bonds | NYSEG | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate						1.61%
First Mortgage Bonds | RG&E
Debt Instrument [Line Items]
Debt instrument principal amount			$ 200
First Mortgage Bonds | CMP
Debt Instrument [Line Items]
Debt instrument principal amount	50
First Mortgage Bonds | SCG
Debt Instrument [Line Items]
Debt instrument principal amount	$ 50

Debt - Schedule of Maturities a

Debt - Schedule of Maturities and Repayments of Long-term Debt (Details) $ in Millions	Dec. 31, 2020USD ($)
Debt Disclosure [Abstract]
2021	$ 313
2022	363
2023	439
2024	612
2025	1,107
Total	$ 2,834

Fair Value of Financial Instr_3

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative delivery period (in years)	2 years
Restricted cash	$ 4	$ 6
RG&E
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of electric load obligations using contracts for a NYISO location	70.00%

Fair Value of Financial Instr_4

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	$ (89)	$ (125)
Derivative Asset, Total	97	95
Netting	81	125
Derivative Liability	(96)	(105)
Equity and other investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	63	51
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	(54)	(54)
Derivative Asset, Total	87	93
Netting	72	92
Derivative Liability	(5)	(8)
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	(35)	(71)
Derivative Asset, Total	8	0
Netting	9	33
Derivative Liability	(3)	(2)
Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	0	0
Derivative Asset, Total	2	2
Netting	0	0
Derivative Liability	(88)	(94)
Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	0	0
Derivative Liability	0	(1)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	5	4
Derivative liabilities, gross	(24)	(32)
Level 1 | Equity and other investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	49	38
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	5	4
Derivative liabilities, gross	(23)	(28)
Level 1 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	0	0
Derivative liabilities, gross	(1)	(4)
Level 1 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	0	0
Derivative liabilities, gross	0	0
Level 1 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities, gross	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	55	63
Derivative liabilities, gross	(40)	(70)
Level 2 | Equity and other investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	14	13
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	31	23
Derivative liabilities, gross	(31)	(43)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	24	40
Derivative liabilities, gross	(9)	(26)
Level 2 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	0	0
Derivative liabilities, gross	0	0
Level 2 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities, gross	0	(1)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	126	153
Derivative liabilities, gross	(113)	(128)
Level 3 | Equity and other investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	0	0
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	105	120
Derivative liabilities, gross	(23)	(29)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	19	31
Derivative liabilities, gross	(2)	(5)
Level 3 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross	2	2
Derivative liabilities, gross	(88)	(94)
Level 3 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities, gross	$ 0	$ 0

Fair Value of Financial Instr_5

Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value as of January 1,	$ 25	$ (15)	$ 6
Gains for the year recognized in operating revenues	8	53	18
Losses for the year recognized in operating revenues	(2)	(2)	(9)
Total gains or losses for the period recognized in operating revenues	6	51	9
Gains recognized in OCI	1	2	0
Losses recognized in OCI	(3)	(3)	(5)
Total gains or losses recognized in OCI	(2)	(1)	(5)
Net change recognized in regulatory assets and liabilities	6	5	(5)
Purchases	(2)	(22)	(6)
Settlements	(15)	4	(10)
Transfers out of Level 3 (a)	(5)	3	(4)
Fair value as of December 31,	13	25	(15)
Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$ 6	$ 51	$ 9

Fair Value of Financial Instr_6

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Details) - Measurement Input, Commodity Forward Price [Member]	Dec. 31, 2020$ / MWh$ / kilowatt-MonthOfEnergy
Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate | $ / kilowatt-MonthOfEnergy	5.30
Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate | $ / kilowatt-MonthOfEnergy	2
NYMEX | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	2.53
NYMEX | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	3.47
NYMEX | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	1.48
AECO | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	1.45
AECO | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	3.24
AECO | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	(0.17)
Ameren | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	26.12
Ameren | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	40.53
Ameren | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	14.73
COB | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	33.30
COB | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	95
COB | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	8.20
ComEd | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	24.10
ComEd | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	39.26
ComEd | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	12.65
ERCOT N hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	32.19
ERCOT N hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	196.95
ERCOT N hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	11.25
ERCOT S hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	32.55
ERCOT S hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	203.37
ERCOT S hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	11.41
Indiana hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	28.23
Indiana hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	43.58
Indiana hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	16.36
Mid C | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	29.76
Mid C | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	95
Mid C | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	4
Minn hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	22.82
Minn hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	37.78
Minn hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	11.52
Noil hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	24
Noil hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	39.01
Noil hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	12.70
PJM W hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	28.46
PJM W hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	59.53
PJM W hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	14.28

Fair Value of Financial Instr_7

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Details)	Dec. 31, 2020$ / kilowatt-MonthOfEnergy
Min. | Risk of non-performance
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0050
Min. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0017
Min. | Forward pricing
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	2
Max. | Risk of non-performance
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0051
Max. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0036
Max. | Forward pricing
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	5.30

Derivative Instruments and He_3

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Consolidated Balance Sheet and Amounts of Derivatives (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset	$ 97	$ 95
Derivative Liability	(96)	(105)
Cash collateral (payable) receivable, asset	(18)	(21)
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	0	0
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	3	1
Derivative liabilities	(3)	(1)
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	1	2
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	1	2
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	5	4
Derivative liabilities	(4)	(2)
Derivative Asset	1	2
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(32)	(39)
Cash collateral (payable) receivable, liability	18	27
Total derivatives as presented in the balance sheet	(14)	(12)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	3	1
Derivative liabilities	(34)	(39)
Derivative Liability	(31)	(38)
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	(1)	(1)
Derivative Liability	(1)	(1)
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(75)	(85)
Cash collateral (payable) receivable, liability	1	1
Total derivatives as presented in the balance sheet	(74)	(84)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	3	2
Derivative liabilities	(78)	(86)
Derivative Liability	(75)	(84)
Networks | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	(1)
Derivative Liability	0	(1)
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	27	22
Cash collateral (payable) receivable, asset	(9)	(11)
Total derivatives as presented in the balance sheet	18	11
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	47	23
Derivative liabilities	(23)	(1)
Derivative Asset	24	22
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	8	0
Derivative liabilities	(5)	0
Derivative Asset	3	0
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	96	112
Cash collateral (payable) receivable, asset	(18)	(30)
Total derivatives as presented in the balance sheet	78	82
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	89	110
Derivative liabilities	(2)	(7)
Derivative Asset	87	103
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	15	18
Derivative liabilities	(6)	(9)
Derivative Asset	9	9
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(3)	(14)
Cash collateral (payable) receivable, liability	0	7
Total derivatives as presented in the balance sheet	(3)	(7)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	2	42
Derivative liabilities	(4)	(48)
Derivative Liability	(2)	(6)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	2	5
Derivative liabilities	(3)	(13)
Derivative Liability	(1)	(8)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(5)	(7)
Cash collateral (payable) receivable, liability	0	6
Total derivatives as presented in the balance sheet	(5)	(1)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	9	13
Derivative liabilities	(11)	(18)
Derivative Liability	(2)	(5)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	7	4
Derivative liabilities	(10)	(6)
Derivative Liability	$ (3)	$ (2)

Derivative Instruments and He_4

Derivative Instruments and Hedging - Net Notional Volume (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)MMBTUMWhgal	Dec. 31, 2019USD ($)MMBTUMWhgal
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 88	$ 85
Renewables | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	3	4
Derivative assets (liabilities), fair value	$ 4	$ 10
Renewables | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	7	9
Derivative assets (liabilities), fair value	$ 11	$ 4
Renewables | Natural gas and other fuel purchase contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	24	29
Derivative assets (liabilities), fair value	$ 0	$ (2)
Renewables | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	12	10
Derivative assets (liabilities), fair value	$ 66	$ 73
Renewables | Basis Swaps | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	35	42
Derivative assets (liabilities), fair value	$ 7	$ 0
Renewables | Basis Swaps | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	2	1
Networks | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	5.6	5.1
Networks | Natural gas purchase contracts (Dth) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	9.5	8.5
Networks | Fleet fuel purchase contracts (Gallons) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount | gal	2.5	2.2

Derivative Instruments and He_5

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ 0	$ (3)	$ (6)
Derivative Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	6	8	1
Electricity
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income			(10)
Electricity | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	17	24
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	55	25
Electricity | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0	0
Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income			$ (1)
Natural Gas | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	1	4
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	4	1
Natural Gas | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	$ 0	$ 0

Derivative Instruments and He_6

Derivative Instruments and Hedging - Additional Information (Details)	12 Months Ended
	Dec. 31, 2020USD ($)instrument	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Jan. 31, 2020USD ($)instrument	Jun. 20, 2019USD ($)	Jan. 31, 2018USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory assets	$ 2,882,000,000	$ 2,861,000,000				$ 11,000,000
Regulatory liabilities	3,411,000,000	3,523,000,000
Gain on derivative		43,000,000
Cash flow hedge gain (loss) to be reclassified within twelve months	(9,000,000)
Derivative collateral obligation to be paid in decrease in credit rating below investment grade	18,000,000
Cash collateral pledged	18,000,000	21,000,000
Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain on foreign currency contracts not designated as hedging instruments	$ 4,000,000	0	$ 0
Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of instruments held | instrument	2
Treasury Lock
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of instruments held | instrument				2
Notional amount				$ 600,000,000
Loss Reclassified from Accumulated OCI into Income	$ 27,000,000
Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(8,000,000)	(2,000,000)
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	57,000,000	38,000,000
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	(1,000,000)	(1,000,000)
Loss Reclassified from Accumulated OCI into Income	5,000,000	7,000,000	8,000,000
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Forward contract to hedge foreign currency exchange risk					$ 100,000,000
Gain (loss) recognized in OCI on derivatives	(4,000,000)	(6,000,000)	$ (6,000,000)
Expected amortization of discontinued cash flow hedges, next fiscal year	(4,000,000)
Unrealized loss	1,000,000
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	$ 51,000,000	55,000,000
Networks | Cash Flow Hedging | Fuel Derivatives
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum length of time hedged in cash flow hedge	12 months
Renewables | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months	$ 3,000,000
UI | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	20.00%
Derivative assets	$ 2,000,000	2,000,000
Regulatory assets	86,000,000	92,000,000
Derivative liabilities	88,000,000	94,000,000
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%
Derivative assets	$ 0	0
Derivative liabilities	$ 85,000,000	$ 92,000,000

Derivative Instruments and He_7

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Interest expense	$ 316	$ 310	$ 303
Purchased power, natural gas and fuel used	1,379	1,509	1,653
Operating revenues	6,320	6,336	6,477
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	(1)	(1)
Loss Reclassified from Accumulated OCI into Income	5	7	8
Operating revenues	5,188	5,164	5,310
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating revenues	1,132	1,184	1,138
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(27)	(24)	(16)
Interest rate contracts | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	8	2	0
Interest rate contracts | Networks | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	0	0
Loss Reclassified from Accumulated OCI into Income	4	6	8
Commodity contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(1)	0	(1)
Loss Reclassified from Accumulated OCI into Income	1	1	0
Commodity contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	1	(5)	(11)
Commodity contracts | Renewables | Revenue
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	6	3	(22)
Operating revenues	6,320	6,336	$ 6,477
Foreign currency exchange contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	1	(1)
Loss Reclassified from Accumulated OCI into Income	$ 0	$ 0

Derivative Instruments and He_8

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 88	$ 85
Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	66	73
Long | Wholesale electricity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	4	10
Long | Natural gas and other fuel purchase contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	0	(2)
Long | Basis Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	7	0
Short | Wholesale electricity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 11	$ 4

Derivative Instruments and He_9

Derivative Instruments and Hedging - Effect of Trading and Non Trading Derivatives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)		$ 43
Operating revenues	$ 6,320	6,336	$ 6,477
Purchased power, natural gas and fuel used	1,379	1,509	1,653
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating revenues	1,132	1,184	1,138
Renewables | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	(2)	6
Renewables | Trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)			4
Renewables | Trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)			(2)
Renewables | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)			0
Renewables | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)			4
Renewables | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(5)	78	(23)
Renewables | Non-trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)			11
Renewables | Non-trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)			(15)
Renewables | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)			(19)
Renewables | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)			$ 0
Renewables | Operating Revenues | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	(2)
Renewables | Operating Revenues | Trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(1)	(1)
Renewables | Operating Revenues | Trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(1)	3
Renewables | Operating Revenues | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	2	(3)
Renewables | Operating Revenues | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	(1)
Renewables | Operating Revenues | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(7)	64
Operating revenues	6,320	6,336
Renewables | Operating Revenues | Non-trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0
Renewables | Operating Revenues | Non-trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	6	40
Renewables | Operating Revenues | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	23
Renewables | Operating Revenues | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(13)	1
Renewables | Purchased power, natural gas and fuel used | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0
Renewables | Purchased power, natural gas and fuel used | Trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0
Renewables | Purchased power, natural gas and fuel used | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)		0
Renewables | Purchased power, natural gas and fuel used | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0
Renewables | Purchased power, natural gas and fuel used | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	2	14
Purchased power, natural gas and fuel used	1,379	1,509
Renewables | Purchased power, natural gas and fuel used | Non-trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(4)
Renewables | Purchased power, natural gas and fuel used | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)		(1)
Renewables | Purchased power, natural gas and fuel used | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 6	$ 15

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Renewal term	40 years
Finance lease liabilities	$ 99	$ 63
Renewables
Lessee, Lease, Description [Line Items]
Finance lease liabilities	$ 47	$ 50
Finance lease term	15 years
Early buyout option term	10 years
Renewables | Generation Facility
Lessee, Lease, Description [Line Items]
Useful life of facility	25 years
Min.
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Max.
Lessee, Lease, Description [Line Items]
Remaining lease term	63 years

Leases - Lease Cost (Details)

Leases - Lease Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Finance lease cost
Amortization of right-of-use assets	$ 17	$ 12
Interest on lease liabilities	4	3
Total finance lease cost	21	15
Operating lease cost	16	18
Short-term lease cost	3	5
Variable lease cost	0	2
Total lease cost	$ 40	$ 40

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Operating Leases
Operating lease right-of-use assets	$ 153	$ 70
Operating lease liabilities, current	8	12
Operating lease liabilities, long-term	154	65
Total operating lease liabilities	162	77
Finance Leases
Other assets	162	133
Other current liabilities	8	9
Other non-current liabilities	91	54
Total finance lease liabilities	$ 99	$ 63
Weighted-average Remaining Lease Term (years)
Finance leases	8 years 1 month 13 days	7 years 7 months 2 days
Operating leases	21 years 4 months 17 days	12 years 11 months 23 days
Weighted-average Discount Rate
Finance leases	3.71%	5.35%
Operating leases	3.21%	3.62%

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 13	$ 13
Operating cash flows from finance leases	3	3
Repayments of financing leases	9	27
Right-of-use assets obtained in exchange for lease obligations:
Finance leases	46	1
Operating leases	$ 94	$ 3

Leases - Lease Maturities (Deta

Leases - Lease Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Finance Leases
2021	$ 10
2022	5
2023	53
2024	23
2025	2
Thereafter	19
Total lease payments	112
Less: imputed interest	(13)
Total	99	$ 63
Operating Leases
2021	15
2022	15
2023	13
2024	10
2025	10
Thereafter	182
Total lease payments	245
Less: imputed interest	(83)
Total	$ 162	$ 77

Commitments and Contingent Li_3

Commitments and Contingent Liabilities - Additional Information (Details) violation in Thousands, $ in Millions

Nov. 20, 2020violation

May 21, 2020

May 20, 2020

Nov. 21, 2019complaint

Jan. 11, 2019complaint

Mar. 22, 2016

Mar. 03, 2015

Oct. 16, 2014

Sep. 30, 2011

Dec. 31, 2020USD ($)

Oct. 31, 2018

Apr. 30, 2018

Dec. 31, 2020USD ($)MW

Dec. 31, 2001plaintiff

Dec. 31, 2019USD ($)

Oct. 30, 2019USD ($)

Apr. 12, 2016USD ($)

Loss Contingencies [Line Items]

Refund period, term

15 months

Approved return on equity

9.88%

Regulatory liabilities

$ 3,137

$ 3,137

$ 3,281

Number of complaints | complaint

2

Number of plaintiffs | plaintiff

2

Requested existing base return on equity base percentage

10.02%

9.88%

Show Cause Order, Period

30 days

Standby letters of credit, surety bonds, guarantees and indemnifications outstanding

678

$ 678

Show Cause Order, Number Of Alleged Violations With Civil Action For Injunctive Relief | violation

11

Power purchase commitments

Loss Contingencies [Line Items]

Power purchase commitment | MW

55

Period of purchase commitment

12 years

Power purchase commitment, remaining period

1 year

Power purchase commitments | Guaranteed output / Guaranteed annual production

Loss Contingencies [Line Items]

Power purchase commitment | MW

34.4

Power sales commitments

Loss Contingencies [Line Items]

Power purchase commitment | MW

55

Period of purchase commitment

12 years

Power purchase commitment, remaining period

1 year

Power sales commitments | Guaranteed output / Guaranteed annual production

Loss Contingencies [Line Items]

Power purchase commitment | MW

34.4

Complaint III

Loss Contingencies [Line Items]

Regulatory liabilities

7

$ 7

Complaint II

Loss Contingencies [Line Items]

Regulatory liabilities

26

26

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 PPAs

$ 259

Requested renewables delay from preliminary proposed ruling period

2 years

Gas Storage Indemnification Claims

Loss Contingencies [Line Items]

Litigation settlement, amount awarded to other party

5

Unfavorable Regulatory Action | Complaint I

Loss Contingencies [Line Items]

Approved return on equity

10.57%

Number of complaints | complaint

4

Unfavorable Regulatory Action | Complaint I | Max.

Loss Contingencies [Line Items]

Approved return on equity

10.42%

11.74%

11.74%

Unfavorable Regulatory Action | Complaint III

Loss Contingencies [Line Items]

Approved return on equity

10.90%

Unfavorable Regulatory Action | Complaint III | Max.

Loss Contingencies [Line Items]

Approved return on equity

12.19%

Unfavorable Regulatory Action | Complaint II

Loss Contingencies [Line Items]

Approved return on equity

9.59%

Refund period

15 months

Before Amendment

Loss Contingencies [Line Items]

Requested return on equity base percentage

11.14%

Beginning in 2019 and Expiring in 2021 | Power purchase commitments | Hydro Capacity And Energy

Loss Contingencies [Line Items]

Power purchase commitment | MW

95.6

Period of purchase commitment

3 years

Beginning in 2019 and Expiring in 2023 | Power purchase commitments | Hydro Capacity And Energy

Loss Contingencies [Line Items]

Power purchase commitment | MW

52

Period of purchase commitment

5 years

Expiring in 2026 | Power sales commitments | Guaranteed output / Guaranteed annual production

Loss Contingencies [Line Items]

Power purchase commitment | MW

12

Amphora Gas Storage USA, LLC | Gas Storage Indemnification Claims

Loss Contingencies [Line Items]

Loss contingency, range of possible loss, portion not accrued

$ 20

Vineyard Wind

Loss Contingencies [Line Items]

Standby letters of credit, surety bonds, guarantees and indemnifications outstanding

$ 88

$ 88

Commitments and Contingent Li_4

Commitments and Contingent Liabilities - Schedule of Forward Purchases and Sales Commitments Under Power, Gas, and Other Arrangements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)
Purchases
2021	$ 889
2022	135
2023	74
2024	48
2025	45
Thereafter	934
Totals	2,125
Sales
2021	178
2022	103
2023	68
2024	41
2025	32
Thereafter	54
Totals	$ 476

Environmental Liabilities (Deta

Environmental Liabilities (Details)	Apr. 24, 2020USD ($)	Sep. 11, 2014USD ($)	Sep. 09, 2011USD ($)	Nov. 30, 2014USD ($)	Jul. 31, 2011USD ($)site	Dec. 31, 2020USD ($)site	Dec. 31, 2019USD ($)	Aug. 04, 2016USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations (sites) | site						26
Number of inactive hazardous waste disposal sites with liability recorded | site						12
Number of inactive hazardous waste disposal sites not expected to incur additional liabilities | site						14
Number of additional inactive hazardous waste disposal sites with liability recorded | site						12
Number of sites where gas was manufactured in the past | site						53
Number of sites for which we have entered into consent orders to investigate and remediate | site						41
Costs related to investigation and remediation						$ 300,000,000	$ 349,000,000
Accrual for environmental loss contingencies		$ 27,000,000				$ 19,000,000
Number of sites court modified decision | site						9
Damages for incurred costs payment amount		$ 22,000,000
Refund of environmental remediation cost paid				$ 5,000,000
Loss contingency, damages sought, value	$ 5,000,000
First Energy
Environmental Exit Cost [Line Items]
Former manufactured gas sites | site					16
Reasonably possible loss, in additional reserve, net of tax					$ 60,000,000
Environmental costs paid			$ 30,000,000
First Energy | Past Costs
Environmental Exit Cost [Line Items]
Accrual for environmental loss contingencies			27,000,000
First Energy | Pre-judgment Interest
Environmental Exit Cost [Line Items]
Environmental costs paid			$ 3,000,000
United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						$ 22,000,000	16,000,000	$ 30,000,000
New York State Registry
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations (sites) | site						16
Number of sites where gas was manufactured in the past | site						6
Maine's Uncontrolled Sites Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations (sites) | site						5
Number of sites where gas was manufactured in the past | site						2
Massachusetts Non- Priority Confirmed Disposal Site List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations (sites) | site						1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations (sites) | site						6
Ten of Twenty-five Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability						$ 6,000,000
Another Eleven Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability						9,000,000
Another Eleven Sites | Min.
Environmental Exit Cost [Line Items]
Estimated environmental liability						13,000,000
Another Eleven 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 | site						3
Maine's Voluntary Response Action Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site						3
Manufactured Gas Plants | Connecticut
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						$ 96,000,000	$ 97,000,000
Manufactured Gas Plants | Min.
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						177,000,000
Manufactured Gas Plants | Max.
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						294,000,000
Properties Where MGPs Had Historically Operated
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						$ 0

Income Taxes - Schedule of Curr

Income Taxes - Schedule of Current and Deferred Taxes Charged to (Benefit) Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current
Federal	$ 3	$ 11	$ 17
State	9	(6)	2
Current taxes charged to expense	12	5	19
Deferred
Federal	67	164	231
State	38	58	(13)
Deferred taxes charged to expense	105	222	218
Production tax credits	(87)	(57)	(68)
Investment tax credits	(1)	(1)	(2)
Total Income Tax Expense	$ 29	$ 169	$ 167

Income Taxes - Schedule of Diff

Income Taxes - Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Tax expense at federal statutory rate	$ 119	$ 170	$ 159
Depreciation and amortization not normalized	(13)	(23)	(5)
Investment tax credit amortization	(1)	(1)	(2)
Tax return related adjustments	1	(2)	(6)
Production tax credits	(87)	(57)	(68)
Tax equity financing arrangements	1	8	0
Federal tax rate impact on held for sale classification	0	0	21
State tax expense (benefit), net of federal benefit	37	41	(9)
Excess ADIT amortization	(42)	0	0
Tax Act - remeasurement	0	0	46
Other, net	14	33	31
Total Income Tax Expense	$ 29	$ 169	$ 167

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred Income Tax Liabilities (Assets)
Property related	$ 4,147	$ 4,007
Unfunded future income taxes	100	101
Federal and state tax credits	(731)	(632)
Federal and state NOL’s	(1,047)	(981)
Joint ventures/partnerships	167	136
Nontaxable grant revenue	(311)	(335)
Pension and other post-retirement benefits	22	43
Tax Act - tax on regulatory remeasurement	(382)	(409)
Valuation allowance	81	48
Other	(127)	(141)
Deferred Income Tax Liabilities	1,919	1,837
Deferred tax assets	2,598	2,498
Deferred tax liabilities	4,517	4,335
Net Accumulated Deferred Income Tax Liabilities	$ 1,919	$ 1,837

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Taxes [Line Items]
Operating loss carryforwards, valuation allowance	$ 65,000,000
Deferred tax assets, valuation allowance	81,000,000	$ 48,000,000
Increase in valuation allowance, deferred tax asset	33,000,000
Unrecognized tax benefits that would impact effective tax rate	107,000,000
Net increase (decrease) to unrecognized tax benefits	0
Federal
Income Taxes [Line Items]
Net operating loss carry forwards	3,800,000,000
Tax credit carryforward, valuation allowance	16,000,000
Increase in valuation allowance, deferred tax asset	12,000,000
Federal | Renewable Energy and Investment
Income Taxes [Line Items]
Tax credit carry forward	695,000,000
State
Income Taxes [Line Items]
Net operating loss carry forwards	324,000,000
Tax credit carry forward	142,000,000
Operating loss carryforwards, valuation allowance	16,000,000
Tax credit carryforward, valuation allowance	65,000,000
Increase in valuation allowance, deferred tax asset	$ 21,000,000

Income Taxes - Schedule of Reco

Income Taxes - Schedule of Reconciliation of Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning Balance	$ 148	$ 153	$ 45
Increases for tax positions related to prior years	11	14	111
Increases for tax positions related to current year	0	16	0
Decreases for tax positions related to prior years	(32)	(18)	(3)
Reduction for tax position related to settlements with taxing authorities	0	(17)	0
Ending Balance	$ 127	$ 148	$ 153

Post-retirement and Similar O_3

Post-retirement and Similar Obligations - Obligations and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Change in benefit obligation
Benefit Obligation as of January 1,	$ 3,669	$ 3,374
Service cost	47	41
Interest cost	107	130
Plan amendments	7	(2)
Actuarial loss	236	347
Curtailments	(21)	0
Benefits paid	(226)	(221)
Benefit Obligation as of December 31,	3,819	3,669
Change in plan assets
Fair Value of Plan Assets as of January 1,	2,848	2,544
Actual return on plan assets	388	460
Employer contributions	84	65
Curtailments	(2)	0
Benefits paid	(226)	(221)
Fair Value of Plan Assets as of December 31,	3,092	2,848
Funded Status as of December 31,	(727)	(821)
Postretirement Benefits
Change in benefit obligation
Benefit Obligation as of January 1,	439	425
Service cost	3	3
Interest cost	13	16
Plan amendments	0	0
Actuarial loss	29	26
Curtailments	0	0
Benefits paid	(32)	(31)
Benefit Obligation as of December 31,	452	439
Change in plan assets
Fair Value of Plan Assets as of January 1,	155	148
Actual return on plan assets	26	22
Employer contributions	18	16
Curtailments	0	0
Benefits paid	(32)	(31)
Fair Value of Plan Assets as of December 31,	167	155
Funded Status as of December 31,	$ (285)	$ (284)

Post-retirement and Similar O_4

Post-retirement and Similar Obligations - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)violation	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial loss due to decreases in discount rates	$ 276	$ 384
Accumulated benefit obligation	$ 3,629	3,451
Amortization period	10 years
Plan assets, number of trust | violation	1
Annual contributions made	$ 49	40	$ 37
Non-Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Other current and other non-current liabilities	59	56
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial loss	236	347
Other current and other non-current liabilities	727	821
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial loss	29	26
Other current and other non-current liabilities	$ 285	$ 284
Postretirement Benefits | VEBA and 401(h) arrangements
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	37.00%
Networks | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected contribution for pension benefit plans during 2021	$ 75
Networks | Pension Benefits | Return-Seeking assets | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	35.00%
Networks | Pension Benefits | Return-Seeking assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	70.00%
Networks | Pension Benefits | Liability-Hedging assets | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	34.00%
Networks | Pension Benefits | Liability-Hedging assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	65.00%
Networks | Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected contribution for pension benefit plans during 2021	$ 17
Networks | Postretirement Benefits | Equity Securities | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	45.00%
Networks | Postretirement Benefits | Equity Securities | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	65.00%
Networks | Postretirement Benefits | Fixed Income | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	25.00%
Networks | Postretirement Benefits | Fixed Income | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	45.00%
Networks | Postretirement Benefits | Other Investment Types | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	5.00%
Networks | Postretirement Benefits | Other Investment Types | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	25.00%
ARHI | Pension Benefits | Return-Seeking assets
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	60.00%
ARHI | Pension Benefits | Liability-Hedging assets
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	40.00%
ARHI | Postretirement Benefits | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	45.00%
ARHI | Postretirement Benefits | Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	50.00%
ARHI | Postretirement Benefits | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	5.00%

Post-retirement and Similar O_5

Post-retirement and Similar Obligations - Summary of Liabilities Amount Recognized (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	$ 0	$ 0
Non-current liabilities	(727)	(821)
Total	(727)	(821)
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(5)	(5)
Non-current liabilities	(280)	(279)
Total	$ (285)	$ (284)

Post-retirement and Similar O_6

Post-retirement and Similar Obligations - Summary of Recognized as Regulatory Assets or Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss	$ 610	$ 706
Prior service cost (credit)	10	4
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss	14	13
Prior service cost (credit)	$ (8)	$ (21)

Post-retirement and Similar O_7

Post-retirement and Similar Obligations - Summary of Amounts Recognized in Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ 21	$ 23
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ (7)	$ (8)

Post-retirement and Similar O_8

Post-retirement and Similar Obligations - Schedule of Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Retirement Benefits [Abstract]
Projected benefit obligation	$ 3,819	$ 3,669
Fair value of plan assets	3,092	2,848
Accumulated benefit obligation	3,629	3,451
Fair value of plan assets	$ 3,092	$ 2,848

Post-retirement and Similar O_9

Post-retirement and Similar Obligations - Schedule of Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations Recognized (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Net Periodic Benefit Cost:
Service cost	$ 47	$ 41
Interest cost	107	130
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	21	23
Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	3	3
Interest cost	13	16
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	(7)	(8)
Networks | Pension Benefits
Net Periodic Benefit Cost:
Service cost	46	41	$ 44
Interest cost	106	128	126
Expected return on plan assets	(198)	(190)	(199)
Amortization of prior service cost (benefit)	1	(1)	1
Amortization of net loss	124	113	149
Net Periodic Benefit Cost	79	91	121
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	(18)	0	0
Net loss (gain)	46	80	175
Amortization of net loss	(124)	(113)	(149)
Current year prior service cost (credit)	7	(2)	0
Amortization of prior service (cost) benefit	(1)	1	(1)
Net loss (gain)	(90)	(34)	25
Total Recognized	(11)	57	146
Networks | Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	3	3	4
Interest cost	13	16	18
Expected return on plan assets	(8)	(7)	(8)
Amortization of prior service cost (benefit)	(9)	(10)	(9)
Amortization of net loss	2	1	6
Net Periodic Benefit Cost	1	3	11
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	0	0	0
Net loss (gain)	11	13	(37)
Amortization of net loss	(2)	(1)	(6)
Current year prior service cost (credit)	0	0	(3)
Amortization of prior service (cost) benefit	9	10	9
Net loss (gain)	18	22	(37)
Total Recognized	19	25	(26)
ARHI | Pension Benefits
Net Periodic Benefit Cost:
Service cost	1	1	0
Interest cost	1	2	2
Expected return on plan assets	(2)	(2)	(2)
Amortization of net loss	2	1	1
Settlement charge	1	0	1
Net Periodic Benefit Cost	3	2	2
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	1	0	1
Amortization of net loss	(2)	(1)	(1)
Amortization of prior service (cost) benefit	0	0	0
Net loss (gain)	(1)	(1)	0
Total Recognized	2	1	2
ARHI | Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	0	0	0
Interest cost	0	0	1
Expected return on plan assets	0	0	0
Amortization of net loss	(1)	(1)	0
Settlement charge	0	0	0
Net Periodic Benefit Cost	(1)	(1)	1
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	0	0	(3)
Amortization of net loss	1	1	0
Amortization of prior service (cost) benefit	0	(2)	0
Net loss (gain)	1	(1)	(3)
Total Recognized	$ 0	$ (2)	$ (2)

Post-retirement and Similar _10

Post-retirement and Similar Obligations - Schedule of Weighted-Average Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Cost (Details) - ARHI	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	2.34%	3.01%
Rate of compensation increase - benefit obligations	3.52%	3.66%
Interest crediting rate	2.87%	2.87%
Discount rate - net periodic benefit	3.01%	3.98%	3.68%
Expected long-term return on plan assets	7.30%	7.30%	7.30%
Rate of compensation increase - net periodic benefit	3.66%	3.79%	3.85%
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	2.19%	2.99%
Rate of compensation increase - benefit obligations	3.50%	3.48%
Discount rate - net periodic benefit	2.99%	3.97%	3.67%
Expected long-term return on plan assets	5.09%	5.08%	5.08%
Rate of compensation increase - net periodic benefit	3.48%	3.50%	3.50%

Post-retirement and Similar _11

Post-retirement and Similar Obligations - Schedule of Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations (Details) - Networks	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50%	4.50%
Min.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	5.25%	6.75%
Max.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.25%	7.75%

Post-retirement and Similar _12

Post-retirement and Similar Obligations - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2020USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2021	$ 211
2022	224
2023	217
2024	219
2025	474
2026 - 2030	765
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2021	31
2022	30
2023	29
2024	29
2025	49
2026 - 2030	$ 100

Post-retirement and Similar _13

Post-retirement and Similar Obligations - Fair Value of Benefits Plan Assets by Asset Category (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	$ 3,092	$ 2,848	$ 2,544
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	2,484	1,708
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	120	42
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	177	87
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	107
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	301	464
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	710	458
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1,018	572
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	50	84
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	592	552
Pension Benefits | Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 1 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	177	87
Pension Benefits | Level 1 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	107
Pension Benefits | Level 1 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	301	464
Pension Benefits | Level 1 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 1 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Pension Benefits | Level 1 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 1 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	6	0
Pension Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1,892	1,156
Pension Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	120	42
Pension Benefits | Level 2 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Pension Benefits | Level 2 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	710	458
Pension Benefits | Level 2 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1,018	572
Pension Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	44	84
Pension Benefits | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Pension Benefits | Level 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Other investments measured at net asset value
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	608	1,140
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	167	155	$ 148
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	164	155
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	6	31
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount		16
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	141	98
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	3	2
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	4
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	9	8
Postretirement Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	142	114
Postretirement Benefits | Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1
Postretirement Benefits | Level 1 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount		16
Postretirement Benefits | Level 1 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	141	98
Postretirement Benefits | Level 1 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 1 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	22	41
Postretirement Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	6	31
Postretirement Benefits | Level 2 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 2 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount		0
Postretirement Benefits | Level 2 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 2 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	3	2
Postretirement Benefits | Level 2 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	4
Postretirement Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	9	8
Postretirement Benefits | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount		0
Postretirement Benefits | Level 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	$ 0
Postretirement Benefits | Other investments measured at net asset value | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	$ 3

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		12 Months Ended
	Jan. 31, 2021	May 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Common stock held in trust (in shares)			413,782	485,810
Release of common stock held in trust (in shares)			72,028	0
Common stock, par value (in dollars per share)			$ 0.01	$ 0.01	$ 0.01	$ 0.01
Treasury shares (in shares)			303,835
Number of shares repurchased during period (in shares)		42,777
Repurchases of common stock			$ 14	$ 12
Subsequent Event
Class of Stock [Line Items]
Release of common stock held in trust (in shares)	292,594
Common Stock
Class of Stock [Line Items]
Issuance of common stock (in shares)			42,777	0
Convertible Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares outstanding (in shares)			0	0
Iberdrola Renewables Holding, Inc
Class of Stock [Line Items]
Percentage of equity owned by parent			81.50%

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	$ 15,539	$ 15,389	$ 15,090
Change	(16)	(11)	(25)
Balance at end of period	15,826	15,539	15,389
Other comprehensive income (loss), defined benefit plan, gain (loss) arising during period, tax	0	0	1
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	(3)	(1)	0
Other comprehensive income (loss), cash flow hedge, gain (loss), before reclassification, tax	(7)	(9)	(7)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	2	3	(7)
Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(1)	(1)	136
Balance at end of period		(1)	(1)
Change in revaluation of defined benefit plans, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(12)	(11)	(14)
Change	0	1	3
Balance at end of period	(12)	(12)	(11)
Change in revaluation of defined benefit plans, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		(2)	0
Balance at end of period			(2)
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(7)	(6)	(6)
Change	(13)	(1)	1
Balance at end of period	(20)	(7)	(6)
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		0	(1)
Balance at end of period			0
Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(13)	9	30
Change	(22)	(22)	(21)
Balance at end of period	(35)	(13)	9
Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		0	0
Balance at end of period			0
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(63)	(64)	(56)
Change	19	11	(8)
Balance at end of period	(44)	(63)	(64)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		(10)	0
Balance at end of period			(10)
Loss on derivatives qualifying as cash flow hedges
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(76)	(55)	(26)
Change	(3)	(11)	(29)
Balance at end of period	(79)	(76)	(55)
Loss on derivatives qualifying as cash flow hedges | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		(10)	0
Balance at end of period			(10)
Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(95)	(72)	(46)
Change	(16)	(11)	(25)
Balance at end of period	$ (111)	(95)	(72)
Accumulated Other Comprehensive Loss | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		$ (12)	(1)
Balance at end of period			$ (12)

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Numerator:
Net income attributable to AVANGRID	$ 581	$ 667	$ 587
Denominator:
Weighted average number of shares outstanding - basic (in shares)	309,494,939	309,491,082	309,503,319
Weighted average number of shares outstanding - diluted (in shares)	309,559,387	309,514,910	309,712,628
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic (in dollars per share)	$ 1.88	$ 2.16	$ 1.90
Earnings Per Common Share, Diluted (in dollars per share)	$ 1.88	$ 2.16	$ 1.89

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	May 08, 2020USD ($)wind_farm	Mar. 02, 2020USD ($)investorwind_farmagreement	Jun. 28, 2019MW	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Variable Interest Entity [Line Items]
Contributions from noncontrolling interests	$ 70	$ 237		$ 312	$ 133	$ 223
Number Of Tax Equity Investors | investor		2
Wind firms that reached commercial operation | wind_farm	3	2
Wind farms expected to be part of Aeolus VII | wind_farm	4
Assets of variable interest entities (VIEs)				37,823	34,394
Liabilities of variable interest entities (VIEs)				21,997	18,855
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)				1,713	806
Liabilities of variable interest entities (VIEs)				$ 107	$ 29
Patriot Wind Farm LLC
Variable Interest Entity [Line Items]
Number of TEF agreements | agreement		2
Proposed wind farm and electricity transmission project capacity (in MW) | MW			688

Grants, Government Incentives_3

Grants, Government Incentives and Deferred Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	$ 1,274	$ 1,385
Disposals	(2)	(3)
Derecognition due to sale		(38)
Recognized in income	(68)	(70)
Balance at end of period	$ 1,204	$ 1,274
Poseidon Project
Deferred Credits and Other Liabilities [Roll Forward]
Ownership percentage sold	50.00%	50.00%
Government grants
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	$ 1,258	$ 1,367
Disposals	(2)	(3)
Derecognition due to sale		(38)
Recognized in income	(66)	(68)
Balance at end of period	1,190	1,258
Other deferred income
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	16	18
Disposals	0	0
Derecognition due to sale		0
Recognized in income	(2)	(2)
Balance at end of period	$ 14	$ 16

Equity Method Investments (Deta

Equity Method Investments (Details) $ in Millions	Dec. 16, 2020USD ($)	Dec. 13, 2019USD ($)	Dec. 31, 2020USD ($)ajointVentureleaseplant	Dec. 31, 2019USD ($)MW	Dec. 31, 2018USD ($)	May 31, 2018MW	Dec. 31, 2020USD ($)ajointVentureleaseplantMW	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 668	$ 645			$ 668	$ 645
Number of lease areas | lease			2				2
Distribution of earnings from equity method investments							$ 22	17	$ 18
Equity method investment, distributions received in RECs							14	9
Capitalized interest costs							8	$ 7
CIP
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage				50.00%				50.00%
South Dokata Wind Farm
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 24				$ 24
Enterprise value	$ 298
Equity method investment, ownership percentage			15.00%				15.00%
South Dokata Wind Farm | Sale of Business
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold	85.00%
Consideration from sale of equity method investment	$ 238
Gain on sale of business, net of tax	12
Gain on sale of business, pre-tax	$ 16
Effective percentage of economic benefits retained	7.97%
Net gain related to remeasurement of retained investment	$ 4
Arizona Wind Farm
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 104	$ 111			$ 104	$ 111
Equity method investment, ownership percentage			50.00%				50.00%
Arizona Wind Farm | Sale of Business
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold		50.00%
Consideration from sale of equity method investment		$ 112
Gain on sale of business, net of tax		96
Gain on sale of business, pre-tax		134
Net gain related to remeasurement of retained investment		$ 50
Coyote Ridge Wind LLC
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold					80.00%				80.00%
Equity method investments			$ 16	14			$ 16	14
Equity method investment, ownership percentage			20.00%				20.00%
Proceeds from sale of portion of subsidiary					$ 144		$ 84
Gain (loss) on sale of equity method investee							$ 4	10	$ 10
Horizon Wind Energy LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			50.00%				50.00%
Number of joint ventures | jointVenture			2				2
Flat Rock Wind Power LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 98	105			$ 98	105
Leased are transmission capacity (in MW) | MW							231
Flat Rock Wind Power II LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments			47	49			$ 47	49
Leased are transmission capacity (in MW) | MW							91
Vineyard Wind
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 245	$ 227			$ 245	$ 227
Equity method investment, ownership percentage			50.00%				50.00%
Leased are transmission capacity (in MW) | MW							5,000
Area of land | a			166,886				166,886
Proposed wind farm and electricity transmission project capacity (in MW) | MW				804		800
Vineyard Wind | 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 | Renewables
Schedule of Equity Method Investments [Line Items]
Contributions to equity method investment							$ 252
Clearway Energy, Inc
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 104	$ 113			$ 104	113
Equity method investment, ownership percentage			50.00%				50.00%
Number of peaking generation plants | plant			2				2
New York TransCo.
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 30	26			$ 30	26
Equity method investment, ownership percentage			20.00%				20.00%
Leased are transmission capacity (in MW) | MW							3,200
Amount funded to date							$ 600
Portion of amount receivable from related parties			$ 0	$ 1			$ 0	$ 1
New York TransCo. | NYSEG
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			20.00%				20.00%
Amount funded to date							$ 120

Other Financial Statements It_3

Other Financial Statements Items - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loss from assets held for sale	$ 0	$ 0	$ 16
Deferred Payment Arrangements
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 78	$ 65
Held for Sale | Gas Trading and Storage Businesses
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loss from assets held for sale			$ 16

Other Financial Statements It_4

Other Financial Statements Items - Schedule of Other Income and (Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Gain on sale of assets	$ 20	$ 148	$ 10
Allowance for funds used during construction	56	46	30
Carrying costs on regulatory assets	28	21	21
Non-service component of net periodic benefit cost	(62)	(79)	(128)
Other	(24)	(15)	1
Total Other Income (Expense)	18	121	(66)
Tatanka Project
Schedule of Investments [Line Items]
Gain (loss) on sale of equity method investee		16
Poseidon Project
Schedule of Investments [Line Items]
Gain (loss) on sale of equity method investee		134
Coyote Ridge Wind LLC
Schedule of Investments [Line Items]
Gain (loss) on sale of equity method investee	$ 4	$ 10	$ 10

Other Financial Statements It_5

Other Financial Statements Items - Schedule of Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Trade receivables and unbilled revenues	$ 1,295	$ 1,151
Allowance for credit losses	(108)	(69)	$ (62)	$ (64)
Total Accounts receivable and unbilled revenues, net	$ 1,187	$ 1,082

Other Financial Statements It_6

Other Financial Statements Items - Schedule of Change in Allowance For Bad Debts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 69	$ 62	$ 64
Current period provision	83	92	74
Write-off as uncollectible	(44)	(85)	(76)
Ending balance	$ 108	$ 69	$ 62

Other Financial Statements It_7

Other Financial Statements Items - Schedule of Prepayments and Other Current Assets (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Prepaid other taxes	$ 135	$ 123
Short-term investments	300	0
Broker margin and collateral accounts	30	33
Other pledged deposits	2	3
Prepaid expenses	41	34
Other	17	6
Total	$ 525	$ 199

Other Financial Statements It_8

Other Financial Statements Items - Schedule of Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Payables and Accruals [Abstract]
Advances received	$ 141	$ 143
Accrued salaries	109	89
Short-term environmental provisions	49	40
Collateral deposits received	42	44
Pension and other postretirement	5	5
Finance leases	8	9
Other	14	6
Total	$ 368	$ 336

Segment Information - Additiona

Segment Information - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)segment	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment	2
Income tax expense	$ 29	$ 169	$ 167
As Reported
Segment Reporting Information [Line Items]
Income tax expense		143	170
Correction
Segment Reporting Information [Line Items]
Income tax expense		26	$ (3)
Networks
Segment Reporting Information [Line Items]
Number of reportable segments | segment	1
Number of operating segments | segment	8
Renewables | As Reported
Segment Reporting Information [Line Items]
Income tax expense		4
Renewables | Correction
Segment Reporting Information [Line Items]
Income tax expense		$ 24

Segment Information - By Segmen

Segment Information - By Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Operating Revenues	$ 6,320	$ 6,336	$ 6,477
Loss from assets held for sale	0	0	16
Depreciation and amortization	987	933	855
Operating income	869	998	1,116
(Losses) earnings from equity method investments	(3)	3	10
Interest expense, net of capitalization	316	310	303
Income tax expense (benefit)	29	169	167
Capital expenditures	2,781	2,735	1,777
Adjusted net income	625	640	676
Property, plant and equipment	26,751	25,196
Equity method investments	668	645
Total Assets	37,823	34,394
Other
Segment Reporting Information [Line Items]
Operating Revenues	1	2	37
Loss from assets held for sale			16
Depreciation and amortization	1	1	0
Operating income	8	15	16
(Losses) earnings from equity method investments	0	0	0
Interest expense, net of capitalization	75	27	10
Income tax expense (benefit)	(11)	(11)	32
Capital expenditures	0	3	0
Adjusted net income	(58)	(17)	13
Property, plant and equipment	10	10
Equity method investments	0	0
Total Assets	364	(1,997)
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	(1)	(14)	(8)
Networks
Segment Reporting Information [Line Items]
Operating Revenues	5,188	5,164	5,310
Networks | Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	(1)	(14)	(6)
Networks | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenues	5,187	5,150	5,304
Loss from assets held for sale			0
Depreciation and amortization	592	549	503
Operating income	877	890	968
(Losses) earnings from equity method investments	10	11	13
Interest expense, net of capitalization	234	269	260
Income tax expense (benefit)	120	152	167
Capital expenditures	1,838	1,610	1,370
Adjusted net income	568	465	481
Property, plant and equipment	17,079	15,829
Equity method investments	134	139
Total Assets	24,592	23,239
Renewables
Segment Reporting Information [Line Items]
Operating Revenues	1,132	1,184	1,138
Renewables | Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	0	0	(2)
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenues	1,132	1,184	1,136
Loss from assets held for sale			0
Depreciation and amortization	394	383	352
Operating income	(16)	93	132
(Losses) earnings from equity method investments	(13)	(8)	(3)
Interest expense, net of capitalization	7	14	33
Income tax expense (benefit)	(80)	28	(32)
Capital expenditures	943	1,122	407
Adjusted net income	115	193	$ 182
Property, plant and equipment	9,662	9,357
Equity method investments	534	506
Total Assets	$ 12,867	$ 13,152

Segment Information - Reconcili

Segment Information - Reconciliation of Consolidated EBITDA to Consolidated Net Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting [Abstract]
Adjusted Net Income	$ 625	$ 640	$ 676
Restructuring charges	(6)	(6)	(4)
Mark-to-market adjustments - Renewables	(5)	76	(25)
Loss from held for sale measurement	0	0	(16)
Impact of the Tax Act	0	0	(46)
Accelerated depreciation from repowering	(9)	(33)	(3)
Impact of COVID-19	(29)	0	0
Merger costs	(6)	0	0
Proceeds from Legal Settlements	(5)	0	0
Income tax impact of adjustments	16	(10)	(6)
Gas Storage, net of tax	0	0	11
Net Income Attributable to Avangrid, Inc.	$ 581	$ 667	$ 587

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Iberdrola, S.A.
Related Party Transaction [Line Items]
Sales To	$ 1	$ 1	$ 1
Purchases From	(43)	(42)	(38)
Iberdrola Renovables Energia, S.L.
Related Party Transaction [Line Items]
Sales To	0	0	0
Purchases From	(9)	(9)	(14)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Sales To	0	0	0
Purchases From	(7)	(3)	(3)
Vineyard Wind
Related Party Transaction [Line Items]
Sales To	9	13	3
Purchases From	0	0	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Sales To	2	1	0
Purchases From	0	0	0
Iberdrola Energia Monterrey, S.A. de C.V.
Related Party Transaction [Line Items]
Sales To	0	0	3
Purchases From	0	0	0
Iberdrola Canada Energy Services, Ltd
Related Party Transaction [Line Items]
Sales To	0	0	0
Purchases From	0	0	(5)
Other
Related Party Transaction [Line Items]
Sales To	0	1	2
Purchases From	$ 0	$ (3)	$ (5)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Loss from assets held for sale	$ 0	$ 0	$ 16,000,000
Iberdrola
Related Party Transaction [Line Items]
Deposit balance	0	150,000,000
Iberdrola Financiacion S A U
Related Party Transaction [Line Items]
Credit facility maximum borrowing capacity	$ 500,000,000
Credit facility initial fees range	0.105%
Credit facility, amount outstanding	$ 0	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Notes payable, related parties	5,000,000	0
Affiliated Entity
Related Party Transaction [Line Items]
Loss from assets held for sale	$ 0
Siemens Gamesa | Iberdrola
Related Party Transaction [Line Items]
Business acquisition, percentage of voting interests acquired	8.10%
Related party transaction, amount	$ 11,000,000	$ 18,000,000

Related Party Transactions - _2

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Iberdrola, S.A.
Related Party Transaction [Line Items]
Owed By	$ 2	$ 1
Owed To	(43)	(42)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(6)	(3)
Siemens Gamesa
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	0	(18)
Vineyard Wind
Related Party Transaction [Line Items]
Owed By	4	5
Owed To	0	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Owed By	5	0
Owed To	0	0
Other
Related Party Transaction [Line Items]
Owed By	1	4
Owed To	$ (1)	$ (1)

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Details) $ / shares in Units, $ in Millions	Mar. 18, 2020installmentshares	Aug. 31, 2020installment$ / sharesshares	Jun. 30, 2020USD ($)shares	May 31, 2020shares	Feb. 29, 2020shares	Oct. 31, 2018$ / sharesshares	Jun. 30, 2018$ / sharesshares	Dec. 31, 2020USD ($)installment$ / sharesshares	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)installmentsetshares	Dec. 31, 2017shares	Dec. 31, 2016$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for stock-based compensation plans (in shares)								2,500,000
Number of PSUs granted (in shares)								6,691
Share-based payment award options grant date fair value (in dollars per share) | $ / shares								$ 49.20
Number of awards set granted | set										2
Number of shares forfeited (in shares)								997,088
Grant date fair value (in dollars per share) | $ / shares								$ 32.42	$ 32.83
Stock-based compensation expense | $								$ 14	$ 3	$ 2
Income tax benefit recognized for stock-based compensation arrangements | $								4	$ 1	$ 1
Unrecognized cost for non-vested PSUs | $								$ 3
Recognition of PSU costs, weighted-average period								2 years
Performance Shares Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs granted (in shares)					208,268
Number of shares issued (in shares)				42,777
Number of shares forfeited (in shares)				2,605
Performance Shares Units | Officers and Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs granted (in shares)									3,881	75,350	85,759	1,298,683
Share-based payment award options grant date fair value (in dollars per share) | $ / shares												$ 31.80
Share-based payment award options requisite service period												7 years
Number of vesting installments | installment								3
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs granted (in shares)		5,000
Number of shares issued (in shares)			60,000
Share-based Payment Arrangement, Cash Used to Settle Award | $			$ 3
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 PSUs granted (in shares)						8,000	60,000
Share-based payment award options grant date fair value (in dollars per share) | $ / shares						$ 47.59	$ 50.40
Number of vesting installments | installment		3								1
Phantom Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs granted (in shares)	167,060
Number of vesting installments | installment	3
Share-based Payment Arrangement, Cash Used to Settle Award | $			$ 2
Share based compensation liability | $								$ 2

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Nonvested PSUs and RSUs (Details)	12 Months Ended
	Dec. 31, 2020$ / sharesshares
Number of PSUs and RSUs
Nonvested Balance – beginning of year (in shares) | shares	1,274,280
Granted (in shares) | shares	6,691
Forfeited (in shares) | shares	(997,088)
Vested (in shares) | shares	(141,716)
Nonvested Balance – end of year (in shares) | shares	142,167
Weighted Average Grant Date Fair Value
Nonvested Balance – beginning of year (in dollars per share) | $ / shares	$ 32.83
Granted (in dollars per share) | $ / shares	49.20
Forfeited (in dollars per share) | $ / shares	31.80
Vested (in dollars per share) | $ / shares	41.44
Nonvested Balance – end of year (in dollars per share) | $ / shares	$ 32.42

Restructuring and Severance R_3

Restructuring and Severance Related Expenses - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Restructuring Cost and Reserve [Line Items]
Severance expenses	$ 2	$ 4	$ 3
Depreciation And Amortization
Restructuring Cost and Reserve [Line Items]
Severance expenses	$ 4	$ 2

Restructuring and Severance R_4

Restructuring and Severance Related Expenses - Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities and Other Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Restructuring Reserve [Roll Forward]
Restructuring Charges	$ 6	$ 6	$ 4
Severance And Lease Restructuring
Restructuring Reserve [Roll Forward]
Restructuring Reserve, Beginning Balance	5
Restructuring Charges	2
Payments for Restructuring	(4)
Restructuring Reserve, Ending Balance	$ 3	$ 5

Subsequent events (Details)

Subsequent events (Details)	Feb. 16, 2021$ / shares	Feb. 15, 2021installmentshares	Feb. 29, 2020shares	Dec. 31, 2020installment$ / sharesshares	Dec. 31, 2019$ / sharesshares	Dec. 31, 2018$ / sharesshares	Dec. 31, 2017shares	Dec. 31, 2016shares
Subsequent Event [Line Items]
Number of PSUs granted (in shares)				6,691
Dividends declared (in dollars per share) | $ / shares				$ 1.76	$ 1.76	$ 1.744
Performance Shares Units
Subsequent Event [Line Items]
Number of PSUs granted (in shares)			208,268
Officers and Employees | Performance Shares Units
Subsequent Event [Line Items]
Number of PSUs granted (in shares)					3,881	75,350	85,759	1,298,683
Number of vesting installments | installment				3
Subsequent Event
Subsequent Event [Line Items]
Dividends declared (in dollars per share) | $ / shares	$ 0.44
Subsequent Event | Officers and Employees | Performance Shares Units
Subsequent Event [Line Items]
Number of PSUs granted (in shares)		1,181,031
Number of vesting installments | installment		3

CONDENSED FINANCIAL INFORMATI_2

CONDENSED FINANCIAL INFORMATION OF PARENT - Statement of Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Condensed Income Statements, Captions [Line Items]
Operating Revenues	$ 6,320	$ 6,336	$ 6,477
Operating Expenses
Taxes other than income taxes, net	619	591	579
Total Operating Expenses	5,451	5,338	5,361
Operating Income	869	998	1,116
Other Income
Other income	18	121	(66)
Interest expense	(316)	(310)	(303)
Income Before Income Tax	568	812	757
Income tax expense	29	169	167
Net Income Attributable to Avangrid, Inc.	581	667	587
AVANGRID
Condensed Income Statements, Captions [Line Items]
Operating Revenues	0	0	0
Operating Expenses
Operating expense	10	3	3
Taxes other than income taxes, net	(11)	(12)	(11)
Total Operating Expenses	(1)	(9)	(8)
Operating Income	1	9	8
Other Income
Other income	35	59	48
Equity earnings of subsidiaries	641	678	596
Interest expense	(109)	(93)	(56)
Income Before Income Tax	568	653	596
Income tax expense	(13)	(14)	9
Net Income Attributable to Avangrid, Inc.	$ 581	$ 667	$ 587

CONDENSED FINANCIAL INFORMATI_3

CONDENSED FINANCIAL INFORMATION OF PARENT - Statements of Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Condensed Statement of Income Captions [Line Items]
Net Income	$ 581	$ 667	$ 587
Comprehensive Income Attributable to Avangrid, Inc.	565	656	562
AVANGRID
Condensed Statement of Income Captions [Line Items]
Net Income	581	667	587
Other comprehensive loss of subsidiaries	(16)	(11)	(25)
Comprehensive Income Attributable to Avangrid, Inc.	$ 565	$ 656	$ 562

CONDENSED FINANCIAL INFORMATI_4

CONDENSED FINANCIAL INFORMATION OF PARENT - Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 1,463	$ 178
Accounts receivable from affiliates	12	10
Prepayments and other current assets	525	199
Total Current Assets	3,777	2,025
Other assets
Other	331	311
Total Other Assets	3,834	3,828
Total Assets	37,823	34,394
Current Liabilities
Current portion of debt	313	730
Notes payable	307	560
Accounts payable and accrued liabilities	1,453	1,361
Accounts payable to subsidiaries	50	64
Interest accrued	70	72
Dividends payable	136	136
Taxes accrued	73	56
Total Current Liabilities	3,069	3,589
Non-current debt	7,478	6,716
Non-current debt to affiliate	3,000	0
Total Liabilities	21,997	18,855
Stockholders' Equity:
Common stock	3	3
Additional paid-in capital	13,665	13,660
Treasury stock	(14)	(12)
Retained earnings	1,666	1,634
Accumulated other comprehensive loss	(111)	(95)
Total Equity	15,826	15,539	$ 15,389	$ 15,090
Total Liabilities and Equity	37,823	34,394
AVANGRID
Current Assets
Cash and cash equivalents	1,438	146
Accounts receivable from affiliates	124	22
Notes receivable from subsidiaries	1,489	2,529
Prepayments and other current assets	357	0
Total Current Assets	3,408	2,697
Investments in subsidiaries	18,356	16,812
Other assets
Deferred income taxes	388	374
Other	3	3
Total Other Assets	391	377
Total Assets	22,155	19,886
Current Liabilities
Current portion of debt	0	456
Notes payable	308	561
Notes payable to subsidiaries	1,375	1,674
Accounts payable and accrued liabilities	12	2
Accounts payable to subsidiaries	9	7
Interest accrued	9	10
Interest accrued subsidiaries	10	18
Dividends payable	136	136
Taxes accrued	0	24
Total Current Liabilities	1,859	2,888
Non-current debt	2,087	1,808
Non-current debt to affiliate	3,000	0
Total Liabilities	6,946	4,696
Stockholders' Equity:
Common stock	3	3
Additional paid-in capital	13,665	13,660
Treasury stock	(14)	(12)
Retained earnings	1,666	1,634
Accumulated other comprehensive loss	(111)	(95)
Total Equity	15,209	15,190
Total Liabilities and Equity	$ 22,155	$ 19,886

CONDENSED FINANCIAL INFORMATI_5

CONDENSED FINANCIAL INFORMATION OF PARENT - Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	$ 1,288	$ 1,588	$ 1,781
Cash Flow from Investing Activities
Payments to affiliates	(3)	(2)	0
Net Cash Used in Investing Activities	(2,858)	(2,708)	(1,554)
Cash Flow from Financing Activities
Non-current debt issuances	1,367	2,137	597
Non-current debt issuance with affiliate	3,000	0	0
Repayments of non-current debt	(1,011)	(346)	(217)
Repurchase of common stock	(2)	0	(4)
Issuance of common stock	(1)	0	(2)
Dividends paid	(545)	(545)	(537)
Net Cash Provided by (Used in) Financing Activities, Total	2,853	1,261	(230)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	1,283	141	(3)
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	184	43	46
Cash, Cash Equivalents and Restricted Cash, End of Year	1,467	184	43
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of amounts capitalized	278	270	224
Cash paid (refunded) for income taxes	8	2	(13)
AVANGRID
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	(142)	(1,299)	(323)
Cash Flow from Investing Activities
Notes receivable from subsidiaries	(73)	633	462
Payments to affiliates	(591)	(399)	(48)
Return of capital from investments in subsidiaries	419	433	116
Other investments	(300)	0	0
Net Cash Used in Investing Activities	(545)	667	530
Cash Flow from Financing Activities
(Repayments) receipts of short-term notes payable from subsidiaries, net	(14)	107	246
(Repayments) receipts of short-term notes payable	(253)	(27)	82
Non-current debt issuances	744	1,243	0
Non-current debt issuance with affiliate	3,000	0	0
Repayments of non-current debt	(950)	0	0
Repurchase of common stock	(2)	0	(4)
Issuance of common stock	(1)	0	(2)
Dividends paid	(545)	(545)	(537)
Net Cash Provided by (Used in) Financing Activities, Total	1,979	778	(215)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	1,292	146	(8)
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	146	0	8
Cash, Cash Equivalents and Restricted Cash, End of Year	1,438	146	0
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of amounts capitalized	111	85	55
Cash paid (refunded) for income taxes	$ 65	$ 43	$ 55

CONDENSED FINANCIAL INFORMATI_6

CONDENSED FINANCIAL INFORMATION OF PARENT - Basis Of Presentation (Details) - USD ($)	Oct. 20, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Net Income		$ (539,000,000)	$ (643,000,000)	$ (590,000,000)
Decrease in retained earnings		$ (1,666,000,000)	(1,634,000,000)
Correction
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Net Income			33,000,000	8,000,000
Decrease in retained earnings			$ 47,000,000	$ 6,000,000
NM Green Holdings, Inc.
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Merger agreement, share price (in dollars per share)	$ 50.30
Merger agreement term, ownership percentage benchmark	15.00%
Merger agreement, termination rights term, extension period	3 months
Merger agreement, termination rights term, termination fees	$ 130,000,000
Merger agreement, termination rights term, termination fees as remedy	184,000,000
Merger agreement, termination rights term, termination fees, out-of-pocket fees and expenses reimbursable limit (up to)	$ 10,000,000

CONDENSED FINANCIAL INFORMATI_7

CONDENSED FINANCIAL INFORMATION OF PARENT - Common Stock (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 16, 2021	Jan. 31, 2021	May 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Common stock, authorized (in shares)				500,000,000	500,000,000
Common stock issued (in shares)				309,794,917	309,752,140
Common stock, outstanding (in shares)				309,077,300	309,005,272
Common stock, par value (in dollars per share)				$ 0.01	$ 0.01	$ 0.01	$ 0.01
Common stock				$ 3	$ 3
Additional paid-in capital				$ 13,665	$ 13,660
Common stock held in trust (in shares)				413,782	485,810
Release of common stock held in trust (in shares)				72,028	0
Number of shares repurchased during period (in shares)			42,777
Treasury shares (in shares)				303,835
Treasury stock				$ 14	$ 12
Dividends declared (in dollars per share)				$ 1.76	$ 1.76	$ 1.744
Convertible Preferred Stock
Business Acquisition [Line Items]
Preferred stock, shares outstanding (in shares)				0	0
Common Stock
Business Acquisition [Line Items]
Issuance of common stock (in shares)				42,777	0
Subsequent Event
Business Acquisition [Line Items]
Release of common stock held in trust (in shares)		292,594
Dividends declared (in dollars per share)	$ 0.44
Iberdrola Renewables Holding, Inc
Business Acquisition [Line Items]
Percentage of equity owned by parent				81.50%
AVANGRID
Business Acquisition [Line Items]
Common stock, authorized (in shares)				500,000,000	500,000,000
Common stock issued (in shares)				309,794,917	309,752,140
Common stock, outstanding (in shares)				309,077,300	309,005,272
Common stock, par value (in dollars per share)				$ 0.01	$ 0.01
Common stock				$ 3	$ 3
Additional paid-in capital				$ 13,665	$ 13,660
Common stock held in trust (in shares)				413,782	485,810
Release of common stock held in trust (in shares)				72,028	0
Number of shares repurchased during period (in shares)			42,777
Treasury shares (in shares)				303,835
Treasury stock				$ 14	$ 12
AVANGRID | Convertible Preferred Stock
Business Acquisition [Line Items]
Preferred stock, shares outstanding (in shares)				0	0
AVANGRID | Common Stock
Business Acquisition [Line Items]
Issuance of common stock (in shares)				42,777	0
AVANGRID | Subsequent Event
Business Acquisition [Line Items]
Dividends declared (in dollars per share)	$ 0.44
AVANGRID | Iberdrola Renewables Holding, Inc
Business Acquisition [Line Items]
Percentage of equity owned by parent				81.50%	81.50%

CONDENSED FINANCIAL INFORMATI_8

CONDENSED FINANCIAL INFORMATION OF PARENT - Long-Term Debt (Details) - USD ($)	Dec. 14, 2020	Apr. 09, 2020	May 16, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Nov. 21, 2017
Debt Instrument [Line Items]
Non-current note issuance				$ 1,367,000,000	$ 2,137,000,000	$ 597,000,000
Iberdrola Loan | Cash and Cash Equivalents | Subordinated Debt
Debt Instrument [Line Items]
Proceeds from short-term debt				1,438,000,000
Iberdrola Loan | Prepaid Expenses and Other Current Assets | Subordinated Debt
Debt Instrument [Line Items]
Proceeds from short-term debt				300,000,000
AVANGRID
Debt Instrument [Line Items]
Non-current note issuance				$ 744,000,000	$ 1,243,000,000	$ 0
AVANGRID | 3.150% Notes due 2024
Debt Instrument [Line Items]
Debt instrument principal amount							$ 600,000,000
Debt instrument, interest rate							3.15%
AVANGRID | 3.800% Notes due 2029
Debt Instrument [Line Items]
Debt instrument principal amount			$ 750,000,000
Debt instrument, interest rate			3.80%
Non-current note issuance			$ 743,000,000
AVANGRID | 3.200% Notes due 2025
Debt Instrument [Line Items]
Debt instrument principal amount							$ 750,000,000
Debt instrument, interest rate			3.20%
Non-current note issuance		$ 744,000,000
AVANGRID | Iberdrola Loan | Subordinated Debt
Debt Instrument [Line Items]
Debt instrument principal amount	$ 3,000,000,000
Debt instrument, interest rate	0.20%
Monthly floating interest rate	0.01%
AVANGRID | Iberdrola Loan | Subordinated Debt | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	0.25%

CONDENSED FINANCIAL INFORMATI_9

CONDENSED FINANCIAL INFORMATION OF PARENT - Cash Dividends Paid by Subsidiaries - Summary (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
AVANGRID Networks
Cash Dividend [Line Items]
Cash dividends paid	$ 419	$ 433	$ 116

CONDENSED FINANCIAL INFORMAT_10

CONDENSED FINANCIAL INFORMATION OF PARENT - Cash Dividends Paid by Subsidiaries - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 3	$ 2	$ 0
AVANGRID
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	591	399	48
Non cash contribution/dividend recorded by parent company	423	219
AVANGRID | United Illuminating Company (UI)
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 590	$ 158	$ 50