Avangrid (AGR) 10-Q 29 Oct 21 2021 Q3 Quarterly report Financial data

Cover Page

Cover Page - shares	9 Months Ended
	Sep. 30, 2021	Oct. 28, 2021
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2021
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 Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		387,204,556
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q3
Entity Central Index Key	0001634997
Current Fiscal Year End Date	--12-31

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Income Statement [Abstract]
Operating Revenues	$ 1,598	$ 1,470	$ 5,041	$ 4,651
Operating Expenses
Purchased power, natural gas and fuel used	319	259	1,085	999
Operations and maintenance	727	634	2,045	1,788
Depreciation and amortization	259	255	756	748
Taxes other than income taxes	155	157	480	469
Total Operating Expenses	1,460	1,305	4,366	4,004
Operating Income	138	165	675	647
Other Income and (Expense)
Other income	13	16	48	15
(Losses) earnings from equity method investments	(1)	1	4	(3)
Interest expense, net of capitalization	(70)	(86)	(218)	(251)
Income Before Income Tax	80	96	509	408
Income tax (benefit) expense	(24)	15	0	21
Net Income	104	81	509	387
Net loss attributable to noncontrolling interests	7	6	34	28
Net Income Attributable to Avangrid, Inc.	$ 111	$ 87	$ 543	$ 415
Earnings Per Common Share, Basic (in dollars per share)	$ 0.29	$ 0.28	$ 1.56	$ 1.34
Earnings Per Common Share, Diluted (in dollars per share)	$ 0.29	$ 0.28	$ 1.56	$ 1.34
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	387,321,484	309,491,082	348,264,388	309,496,234
Diluted (in shares)	387,676,085	309,550,126	348,714,535	309,554,838

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Statement of Comprehensive Income [Abstract]
Net Income	$ 104	$ 81	$ 509	$ 387
Other Comprehensive Income (Loss)
Unrealized loss from equity method investment, net of income taxes of $1 and $0 for the three months ended, respectively, and $(3) and $0 for the nine months ended, respectively	(6)	0	(9)	0
Unrealized loss during the period on derivatives qualifying as cash flow hedges, net of income tax of $(23) and $(3) for the three months ended, respectively, and $(49) and $(8) for the nine months ended, respectively	(73)	(15)	(173)	(31)
Reclassification to net income of losses on cash flow hedges, net of income taxes $(2) and $0 for the three months ended, respectively, and $(6) and $1 for the nine months ended, respectively	5	9	10	12
Other Comprehensive Income (Loss)	(74)	(6)	(172)	(19)
Comprehensive income	30	75	337	368
Net loss attributable to noncontrolling interests	7	6	34	28
Comprehensive Income Attributable to Avangrid, Inc.	$ 37	$ 81	$ 371	$ 396

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Statement of Comprehensive Income [Abstract]
Unrealized loss from equity method investment, taxes	$ 1	$ 0	$ (3)	$ 0
Unrealized loss on derivatives qualifying as cash flow hedges, taxes	(23)	(3)	(49)	(8)
Reclassification to net income of losses on cash flow hedges, taxes	$ (2)	$ 0	$ (6)	$ 1

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 1,410	$ 1,463
Accounts receivable and unbilled revenues, net	1,105	1,187
Accounts receivable from affiliates	7	12
Derivative assets	114	18
Fuel and gas in storage	136	93
Materials and supplies	189	169
Prepayments and other current assets	326	525
Regulatory assets	340	310
Total Current Assets	3,627	3,777
Total Property, Plant and Equipment ($1,608 and $1,637 related to VIEs, respectively)	28,158	26,751
Operating lease right-of-use assets	127	153
Equity method investments	571	668
Other investments	60	68
Regulatory assets	2,500	2,572
Other Assets
Goodwill	3,119	3,119
Intangible assets	296	305
Derivative assets	74	79
Other	347	331
Total Other Assets	3,836	3,834
Total Assets	38,879	37,823
Current Liabilities
Current portion of debt	336	313
Notes payable	96	307
Notes payable to affiliates	2	0
Interest accrued	79	70
Accounts payable and accrued liabilities	1,402	1,453
Accounts payable to affiliates	50	50
Dividends payable	170	136
Taxes accrued	84	73
Operating lease liabilities	14	8
Derivative liabilities	94	17
Other current liabilities	418	368
Regulatory liabilities	367	274
Total Current Liabilities	3,112	3,069
Regulatory liabilities	3,054	3,137
Other Non-current Liabilities
Deferred income taxes	1,960	1,919
Deferred income	1,147	1,204
Pension and other postretirement	908	1,007
Operating lease liabilities	124	154
Derivative liabilities	163	79
Asset retirement obligations	225	210
Environmental remediation costs	297	292
Other	577	448
Total Other Non-current Liabilities	5,401	5,313
Non-current debt	7,486	7,478
Non-current debt to affiliate	0	3,000
Total Non-current Liabilities	15,941	18,928
Total Liabilities	19,053	21,997
Commitments and Contingencies
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 387,678,630 and 309,794,917 shares issued; 387,204,556 and 309,077,300 shares outstanding, respectively	3	3
Additional paid in capital	17,675	13,665
Treasury stock	(16)	(14)
Retained earnings	1,723	1,666
Accumulated other comprehensive loss	(283)	(111)
Total Stockholders’ Equity	19,102	15,209
Non-controlling interests	724	617
Total Equity	19,826	15,826
Total Liabilities and Equity	$ 38,879	$ 37,823

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Property, plant and equipment	$ 28,158	$ 26,751
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, authorized (in shares)	500,000,000	500,000,000
Common stock, issued (in shares)	387,678,630	309,794,917
Common stock, outstanding (in shares)	387,204,556	309,077,300
Variable Interest Entity, Primary Beneficiary
Property, plant and equipment	$ 1,608	$ 1,637

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Cash Flow from Operating Activities:
Net Income	$ 509	$ 387
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	756	748
Regulatory assets/liabilities amortization and carrying cost	75	63
Pension cost	34	60
(Earnings) losses from equity method investments	(4)	3
Distributions of earnings received from equity method investments	14	15
Unrealized loss (gain) on marked-to-market derivative contracts	84	(9)
Deferred taxes	23	11
Other non-cash items	(41)	(35)
Changes in operating assets and liabilities:
Current assets	(115)	7
Noncurrent assets	(165)	(152)
Current liabilities	(1)	24
Noncurrent liabilities	(175)	(30)
Net Cash Provided by Operating Activities	994	1,092
Cash Flow from Investing Activities:
Capital expenditures	(1,897)	(1,960)
Contributions in aid of construction	53	35
Proceeds from sale of assets	6	12
Proceeds from notes receivable from affiliates	4	2
Distributions received from equity method investments	141	3
Other investments and equity method investments, net	228	(48)
Net Cash Used in Investing Activities	(1,465)	(1,956)
Cash Flow from Financing Activities:
Non-current debt issuances	347	967
Repayments of non-current debt	(302)	(511)
Repayment of non-current debt with affiliate	(3,000)	0
(Repayments) receipts of other short-term debt, net	(307)	441
Repayments of financing leases	(5)	(7)
Repurchase of common stock	(2)	(2)
Issuance of common stock	3,998	(1)
Distributions to noncontrolling interests	(9)	(5)
Contributions from noncontrolling interests	141	312
Dividends paid	(443)	(408)
Net Cash Provided by Financing Activities	418	786
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(53)	(78)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	1,467	184
Cash, Cash Equivalents and Restricted Cash, End of Period	1,414	106
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	201	206
Cash paid for income taxes	$ 8	$ 4

Condensed Consolidated Statem_5

Condensed Consolidated Statements of Changes in Equity (unaudited) - 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 Loss	Noncontrolling Interests
Balance, beginning of period (in shares) at Dec. 31, 2019	[1]					309,005,272
Balance, beginning of period at Dec. 31, 2019		$ 15,539	$ (1)	$ 15,190	$ (1)	$ 3		$ 13,660	$ (12)	$ 1,634	$ (1)	$ (95)	$ 349
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		387		415						415			(28)
Other comprehensive income (loss), net of tax		(19)		(19)								(19)
Comprehensive income		368
Dividends declared		(408)		(408)						(408)
Distributions to noncontrolling interests		(5)											(5)
Contributions from noncontrolling interests		312		(3)						(3)			315
Release of common stock held in trust (in shares)	[1]					213
Issuances of common stock (in shares)	[1]					42,777
Issuance of common stock		(1)		(1)				(1)
Repurchase of common stock (in shares)	[1]					(42,777)
Repurchase of common stock		(2)		(2)					(2)
Stock-based compensation		5		5				5
Balance, end of period (in shares) at Sep. 30, 2020	[1]					309,005,485
Balance, end of period at Sep. 30, 2020		15,807		15,176		$ 3		13,664	(14)	1,637		(114)	631
Balance, beginning of period (in shares) at Jun. 30, 2020	[1]					309,005,485
Balance, beginning of period at Jun. 30, 2020		15,869		15,231		$ 3		13,664	(14)	1,686		(108)	638
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		81		87						87			(6)
Other comprehensive income (loss), net of tax		(6)		(6)								(6)
Comprehensive income		75
Dividends declared		(136)		(136)						(136)
Distributions to noncontrolling interests		(1)											(1)
Balance, end of period (in shares) at Sep. 30, 2020	[1]					309,005,485
Balance, end of period at Sep. 30, 2020		$ 15,807		15,176		$ 3		13,664	(14)	1,637		(114)	631
Balance, beginning of period (in shares) at Dec. 31, 2020		309,077,300				309,077,300	[1]
Balance, beginning of period at Dec. 31, 2020		$ 15,826		15,209		$ 3		13,665	(14)	1,666		(111)	617
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		509		543						543			(34)
Other comprehensive income (loss), net of tax		(172)		(172)								(172)
Comprehensive income		337
Dividends declared		(477)		(477)						(477)
Distributions to noncontrolling interests		(9)											(9)
Contributions from noncontrolling interests		141		(9)						(9)			150
Release of common stock held in trust (in shares)	[1]					296,854
Issuances of common stock (in shares)	[1]					77,883,713
Issuance of common stock		3,998		3,998				3,998
Repurchase of common stock (in shares)	[1]					(53,311)
Repurchase of common stock		(2)		(2)					(2)
Stock-based compensation		$ 12		12				12
Balance, end of period (in shares) at Sep. 30, 2021		387,204,556				387,204,556	[1]
Balance, end of period at Sep. 30, 2021		$ 19,826		19,102		$ 3		17,675	(16)	1,723		(283)	724
Balance, beginning of period (in shares) at Jun. 30, 2021	[1]					387,204,556
Balance, beginning of period at Jun. 30, 2021		19,835		19,239		$ 3		17,671	(16)	1,790		(209)	596
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		104		111						111			(7)
Other comprehensive income (loss), net of tax		(74)		(74)								(74)
Comprehensive income		30
Dividends declared		(170)		(170)						(170)
Distributions to noncontrolling interests		(4)											(4)
Contributions from noncontrolling interests		131		(8)						(8)			139
Stock-based compensation		$ 4		4				4
Balance, end of period (in shares) at Sep. 30, 2021		387,204,556				387,204,556	[1]
Balance, end of period at Sep. 30, 2021		$ 19,826		$ 19,102		$ 3		$ 17,675	$ (16)	$ 1,723		$ (283)	$ 724
[1]	(*) Par value of share amounts is $0.01

Condensed Consolidated Statem_6

Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Statement of Stockholders' Equity [Abstract]
Other comprehensive income (loss), tax	$ (24)	$ (3)	$ (58)	$ (7)
Dividends declared (in dollars per share)	$ 0.44	$ 0.44	$ 1.32	$ 1.32
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01	$ 0.01

Background and Nature of Operat

Background and Nature of Operations	9 Months Ended
	Sep. 30, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Background and Nature of Operations	Background and Nature of Operations Avangrid, Inc. (AVANGRID, we or the Company), is an energy services holding company engaged in the regulated energy transmission and distribution business through its principal subsidiary, Avangrid Networks, Inc. (Networks), and in the renewable energy generation business through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.5% of the outstanding common stock of AVANGRID. The remaining outstanding shares are owned by various shareholders with approximately 14.8% of AVANGRID's outstanding shares publicly traded on the New York Stock Exchange (NYSE). Proposed Merger with PNMR On October 20, 2020, AVANGRID, PNM Resources, Inc., a New Mexico corporation (PNMR) and NM Green Holdings, Inc., a New Mexico corporation and wholly-owned subsidiary of AVANGRID (Merger Sub), entered into an Agreement and Plan of Merger (Merger Agreement), pursuant to which Merger Sub is expected to merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of AVANGRID (Merger). Pursuant to the Merger Agreement, each issued and outstanding share of the common stock of PNMR (PNMR common stock) (other than (i) the issued shares of PNMR common stock that are owned by AVANGRID, Merger Sub, PNMR or any wholly-owned subsidiary of AVANGRID or PNMR, which will be automatically cancelled at the time the Merger is consummated and (ii) shares of PNMR common stock held by a holder who has not voted in favor of, or consented in writing to, the Merger who is entitled to, and who has demanded, payment for fair value of such shares) will be converted, at the time the Merger is consummated, into the right to receive $50.30 in cash (Merger Consideration). Consummation of the Merger (Closing) is subject to the satisfaction or waiver of certain customary closing conditions, including, without limitation, the approval of the Merger Agreement by the holders of at least a majority of the outstanding shares of PNMR common stock entitled to vote thereon, the absence of any material adverse effect on PNMR, the receipt of certain required regulatory approvals (including approvals from the Public Utility Commission of Texas (PUCT), the New Mexico Public Regulation Commission (NMPRC), the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Committee on Foreign Investment in the United States (CFIUS), the Nuclear Regulatory Commission (NRC) and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976), the Four Corners Divestiture Agreements (as defined below) being in full force and effect and all applicable regulatory filings associated therewith being made, as well as holders of no more than 15% of the outstanding shares of PNMR common stock validly exercising their dissenters’ rights. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. As of October 29, 2021, the Merger has obtained all regulatory approvals except from NMPRC. The final approval is expected to be received, and the Merger is expected to close, in the fourth quarter of 2021. The Merger Agreement 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. The Merger Agreement provides for certain customary termination rights including the right of either party to terminate the Merger Agreement if the Merger is not completed on or before January 20, 2022 (subject to a three-month extension by either party if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). The Merger Agreement further provides that, upon termination of the Merger Agreement under certain specified circumstances (including if AVANGRID terminates the Merger Agreement due to a change in recommendation of the board of directors of PNMR or if PNMR terminates the Merger Agreement to accept a superior proposal (as defined in the Merger Agreement)), PNMR will be required to pay AVANGRID a termination fee of $130 million. In addition, the Merger Agreement provides that (i) if the Merger Agreement is terminated by either party due to a failure of a regulatory closing condition and such failure is the result of AVANGRID’s breach of its regulatory covenants, or (ii) AVANGRID fails to effect the Closing when all closing conditions have been satisfied and it is otherwise obligated to do so under the Merger Agreement, then, in either such case, upon termination of the Merger Agreement, AVANGRID will be required to pay PNMR a termination fee of $184 million as the sole and exclusive remedy. Upon the termination of the Merger Agreement under certain specified circumstances involving a breach of the Merger Agreement, either PNMR or AVANGRID will be required to reimburse the other party’s reasonable and documented out-of-pocket fees and expenses up to $10 million (which amount will be credited toward, and offset against, the payment of any applicable termination fee). In connection with the Merger, Iberdrola has provided AVANGRID a commitment letter (Iberdrola Funding Commitment Letter), pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration. On April 15, 2021, AVANGRID entered into a side letter agreement with Iberdrola, which sets forth certain terms and conditions relating to the Iberdrola Funding Commitment Letter (the Side Letter Agreement). The Side Letter Agreement provides that any drawing in the form of indebtedness made by the Corporation pursuant to the Funding Commitment Letter shall bear interest at an interest rate equal to 3-month LIBOR plus 0.75% per annum calculated on the basis 360-day year for the actual number of days elapsed and, commencing on the date of the Funding Commitment Letter, we shall pay Iberdrola a facility fee equal to 0.12% per annum on the undrawn portion of the funding commitment set forth in the Funding Commitment Letter. On May 18, 2021, we issued 77,821,012 shares of common stock in two private placements. Iberdrola purchased 63,424,125 shares and Hyde Member LLC, a Delaware limited liability company and a wholly owned subsidiary of Qatar Investment Authority, purchased 14,396,887 shares of our common stock, par value $0.01 per share, at the purchase price of $51.40 per share, which was the closing price of the shares of our common stock on the NYSE as of May 11, 2021. Proceeds of the private placements were $4,000 million. $3,000 million of the proceeds were used to repay the Iberdrola Loan. After the effect of the private placements, Iberdrola retained its 81.5% ownership interest in AVANGRID.

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation The accompanying condensed consolidated financial statements should be read in conjunction with the Form 10-K for the fiscal year ended December 31, 2020. The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts have been eliminated in consolidation. The year-end balance sheet data was derived from audited financial statements. The unaudited condensed consolidated financial statements for the interim periods have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the interim condensed consolidated financial statements do not include all the information and note disclosures required by U.S. GAAP for complete financial statements. Preparation of the accompanying unaudited financial statements requires management to make estimates and assumptions that affect the amounts reported during the periods covered by the related financial statements and accompanying disclosures. We continue to utilize information reasonably available to us; however, the business and economic uncertainty resulting from the global pandemic of the novel coronavirus (COVID-19) has made such estimates and assumptions more difficult to assess and calculate. Impacted estimates include, but are not limited to, evaluations of certain long-lived assets and goodwill for impairment, expected credit losses and potential regulatory deferral or recovery of certain costs. While there have been no material impacts from COVID-19 on financial results, actual results could differ from those estimates, which could result in material impacts to our consolidated financial statements in future reporting periods. In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated financial statements for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three and nine months ended September 30, 2021, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2021.

Significant Accounting Policies

Significant Accounting Policies and New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2021
Accounting Policies [Abstract]
Significant Accounting Policies and New Accounting Pronouncements	Significant Accounting Policies and New Accounting Pronouncements The new accounting pronouncements we have adopted as of January 1, 2021, and reflected in our condensed consolidated financial statements are described below. There have been no other material changes to the significant accounting policies described in our Form 10-K for the fiscal year ended December 31, 2020, except for those described below resulting from the adoption of new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB). Adoption of New Accounting Pronouncements (a) Simplifying the accounting for income taxes In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes , eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation; (2) exceptions to accounting for basis differences in equity method investments when there are ownership changes in foreign investments; and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for: (1) franchise taxes that are partially based on income; (2) transactions with a government that result in a step up in the tax basis of goodwill; (3) separate financial statements of legal entities that are not subject to tax; and (4) enacted changes in tax laws in interim periods. We adopted the amendments effective January 1, 2021, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. We are applying the amendments on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment requirement. (b) Improvements to lessor accounting for certain leases with variable lease payments In July 2021, the FASB issued amendments to make targeted improvements to ASC 842 for lessor’s accounting for certain leases with variable lease payments, which affect lease classification. The amendments require a lessor to classify and account for a lease with variable lease payments as an operating lease if (a) the lease would have been classified as a sales-type lease or a direct financing lease and (b) the lessor would have otherwise recognized a day-one loss. The amendments are effective for fiscal years beginning after December 15, 2021, for all entities, and interim periods within those fiscal years for public business entities, with early application permitted. We have elected to early apply the amendments effective October 1, 2021, and apply the amendments prospectively to leases that commence or are modified on or after that date. Our adoption does not materially affect our consolidated results of operations, financial position and cash flows. Accounting Pronouncements Issued but Not Yet Adopted The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2020, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements. (a) Facilitation of the effects of reference rate reform on financial reporting, and subsequent scope clarification In March 2020, the FASB issued amendments and created ASC 848 to provide temporary optional guidance to entities to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments respond to concerns about structural risks of interbank offered rates, and particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR). The guidance is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform, around the end of 2021. The guidance applies to contracts that have modified terms that affect, or have the potential to affect, the amount or timing of contractual cash flows resulting from the discontinuance of the reference rate reform. The amendments are effective for all entities as of March 12, 2020, through December 31, 2022, although the FASB has indicated it will monitor developments in the marketplace and consider whether developments warrant an extension. In January 2021, the FASB issued amendments to clarify the scope of ASC 848 and respond to questions from stakeholders about whether ASC 848 can be applied to derivative instruments that do not reference a rate that is expected to be discontinued but that use an interest rate for margining, discounting, or contract price alignment that is modified because of reference rate reform. The modification, commonly referred to as the “discounting transition,” may have accounting implications, raising concerns about the need to reassess previous accounting determinations related to those derivatives and about the possible hedge accounting consequences of the discounting transition. The amendments clarify that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition, capture the incremental consequences of the scope clarification and tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments are effective immediately, and may be elected retrospectively to eligible modifications as of any date from the beginning of the interim period that includes March 12, 2020, or prospectively to new modifications made on or after any date within the interim period that includes January 7, 2021. We expect our adoption of reference rate reform and the subsequent scope clarification will not materially affect our consolidated results of operations, financial position and cash flows. (b) Accounting for revenue contracts with customers acquired in a business combination In October 2021, the FASB issued amendments related to the accounting for revenue contracts acquired in a business combination. The amendments require an entity (acquirer) to recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with ASC 606, Revenue from Contracts with Customers . At the acquisition date, an acquirer should account for the related revenue contract in accordance with ASC 606 as if it had originated the contracts. Generally, this should result in an acquirer recognizing and measuring the acquired contract assets and contract liabilities consistent with how they were recognized and measured in the acquiree’s financial statements. The amendments also provide certain practical expedients for acquirers when recognizing and measuring acquired contract assets and contract

Revenue

Revenue	9 Months Ended
	Sep. 30, 2021
Revenue from Contract with Customer [Abstract]
Revenue	Revenue We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale. The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about our reportable segments, refer to Note 13. Networks Segment Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts, with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas. Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. We traditionally invoice our customers by applying approved base rates to usage. Maine state law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer. The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service. Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms (RDMs), other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives or ARPs. Renewables Segment Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all or a percentage of the unit’s output. Renewables also has unbundled sales of electric energy and capacity, RECs and natural gas, which are generally for periods of less than a year. The performance obligations in substantially all of both bundled and unbundled arrangements for electricity and natural gas are satisfied over time, for which we record revenue based on the amount invoiced to the customer for the actual energy delivered. The performance obligation for stand-alone RECs is satisfied at a point in time, for which we record revenue when the performance obligation is satisfied upon delivery of the REC. Renewables classifies certain contracts for the sale of electricity as derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of ASC 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other ASC 606 revenue, which we recognize based on the amount invoiced to the customer. Other Other, which does not represent a segment, includes miscellaneous Corporate revenues and intersegment eliminations. Contract Costs and Contract Liabilities We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in December 2021 upon commercial operation. At both September 30, 2021 and December 31, 2020, contract assets totaled $9 million and are presented in "Other non-current assets" on our condensed consolidated balance sheets. We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period, and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. At September 30, 2021 and December 31, 2020, TCC contract liabilities totaled $6 million and $9 million, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. For the three and nine months ended September 30, 2021, we recognized as revenue $6 million and $15 million, respectively, and for the three and nine months ended September 30, 2020, we recognized $6 million and $16 million, respectively. For the three and nine months ended September 30, 2021 and 2020, revenues disaggregated by major source for our reportable segments are as follows: Three Months Ended September 30, 2021 Nine Months Ended September 30, 2021 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,105 $ — $ — $ 1,105 $ 2,959 $ — $ — $ 2,959 Regulated operations – natural gas 214 — — 214 1,034 — — 1,034 Nonregulated operations – wind — 205 — 205 — 819 — 819 Nonregulated operations – solar — 10 — 10 — 21 — 21 Nonregulated operations – thermal — 14 — 14 — 42 — 42 Other(a) 17 1 (2) 16 41 74 (2) 113 Revenue from contracts with customers 1,336 230 (2) 1,564 4,034 956 (2) 4,988 Leasing revenue 1 — — 1 6 — — 6 Derivative revenue — 22 — 22 — (72) — (72) Alternative revenue programs 8 — — 8 77 — — 77 Other revenue 12 (9) — 3 32 10 — 42 Total operating revenues $ 1,357 $ 243 $ (2) $ 1,598 $ 4,149 $ 894 $ (2) $ 5,041 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2020 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 984 $ — $ — $ 984 $ 2,701 $ — $ — $ 2,701 Regulated operations – natural gas 166 — — 166 910 — — 910 Nonregulated operations – wind — 200 — 200 — 639 — 639 Nonregulated operations – solar — 6 — 6 — 16 — 16 Nonregulated operations – thermal — 13 — 13 — 27 — 27 Other(a) 12 28 (4) 36 38 75 (4) 109 Revenue from contracts with customers 1,162 247 (4) 1,405 3,649 757 (4) 4,402 Leasing revenue 2 — — 2 5 — — 5 Derivative revenue — 25 — 25 — 111 — 111 Alternative revenue programs 24 — — 24 109 — — 109 Other revenue 9 4 1 14 16 8 — 24 Total operating revenues $ 1,197 $ 276 $ (3) $ 1,470 $ 3,779 $ 876 $ (4) $ 4,651 (a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate and intersegment eliminations. As of September 30, 2021 and December 31, 2020, accounts receivable balances related to contracts with customers were approximately $1,043 million and $1,151 million, respectively, including unbilled revenues of $266 million and $341 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets. As of September 30, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of September 30, 2021 2022 2023 2024 2025 2026 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 6 $ 1 $ 1 $ — $ — $ — $ 8 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 26 18 14 12 10 65 145 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 39 23 10 3 3 2 80 Total operating revenues $ 71 $ 42 $ 25 $ 15 $ 13 $ 67 $ 233 As of September 30, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2021 was $25 million.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	9 Months Ended
	Sep. 30, 2021
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When a regulatory order for the specific costs does not exist, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in rate base or accruing carrying costs are regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. As of September 30, 2021, the total net amount of these items is an asset of approximately $1,306 million. CMP Distribution Rate Case In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17 million, or approximately 7.00%, based on an allowed ROE of 9.25% and a 50.00% equity ratio. The rate increase was effective March 1, 2020. The MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a rolling average period of 18 months, which commenced on March 1, 2020. CMP has met the required rolling average benchmarks for all four of these quality measures and on September 20, 2021, filed with the MPUC a request for removal of the management efficiency adjustment. In addition to requesting the lifting of the management efficiency adjustment, CMP requested an accounting order to allow it to defer for future recovery the revenues it would effectively lose by not having the adjustment lifted by September 1, 2021. 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. On July 12, 2021, the management audit report was issued and recommended retaining the current cap on management service costs. The report identified CMP's progress in delivering on several operational outcomes for its customers and recommended additional opportunities for improvement. NYSEG and RG&E Rate Plans On November 19, 2020, the NYPSC approved a new three-year rate plan for NYSEG & RG&E (2020 Joint Proposal), with modifications to the rate increases at the two electric businesses. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. The approved rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as COVID-19 relief for customers and additional funding for vegetation management, hardening/resiliency and emergency preparedness. The rate plans continue the RAM designed to return or collect certain defined reconciled revenues and costs, have new depreciation rates and continue existing RDMs for each business. The 2020 Joint Proposal bases delivery revenues on an 8.80% ROE and 48.00% equity ratio; however, for the earnings sharing mechanism (ESM), the equity ratio is the lower of the actual equity ratio or 50.00%. The below table provides a summary of the approved delivery rate increases and delivery rate percentages, including rate levelization and excluding energy efficiency, which is a pass-through, for all four businesses. Rate years 2 and 3 commence on May 1, 2021 and 2022, respectively. Year 1 Year 2 Year 3 Rate Increase Delivery Rate % Rate Increase Delivery Rate % Rate Increase Delivery Rate % Utility (Millions) Increase (Millions) Increase (Millions) Increase 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 In 2016, the Connecticut Public Utilities Regulatory Authority (PURA) approved new distribution rate schedules for The United Illuminating Company (UI) for three years, which became effective January 1, 2017 and, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50.00% equity ratio, continued UI’s existing ESM pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist. In 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism, ESM, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on an ROE of 9.25% and an equity ratio of approximately 52.00%. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist. In 2018, PURA approved new tariffs for Connecticut Natural Gas Corporation (CNG) effective January 1, 2019 for a three-year rate plan with annual rate increases. The new tariffs continued the RDM and DIMP mechanism. ESM and tariff increases are based on an ROE of 9.30% and an equity ratio of 54.00% in 2019, 54.50% in 2020 and 55.00% in 2021. In 2019, the Massachusetts Department of Public Utilities (DPU) approved new distribution rates for BGC. The distribution rate increase is based on a 9.70% ROE and 54.00% equity ratio. The new tariffs provide for the implementation of an RDM and pension expense tracker and also provide that BGC will not file to change base distribution rates to become effective before November 1, 2021. Connecticut Energy Legislation On October 7, 2020, the Governor of Connecticut signed into law an energy bill that, among other things, instructs PURA to revise the rate-making structure in Connecticut to adopt performance-based rates for each electric distribution company, increases the maximum civil penalties assessable for failures in emergency preparedness, and provides for certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines. Pursuant to the legislation, on October 30, 2020, PURA reopened a docket related to new rate design and review, expanding the scope to consider (a) the implementation of an interim rate decrease; (b) low income rates; and (c) economic development rates. Separately, UI was due to make its annual RAM filing on March 8, 2021 for the approval of its RAM Rate Components reconciliations: Generation Services Charges, By-passable Federally Mandated Congestion Costs, System Benefits Charge, Transmission Adjustment Charge and RDM. On March 9, 2021, UI, jointly with the Office of the CT Attorney General, the Office of CT Consumer Counsel, DEEP and PURA’s Office of Education, Outreach, and Enforcement entered into a settlement agreement and filed a motion to approve the settlement agreement, which addressed issues in both dockets. In an order dated June 23, 2021, PURA approved the as amended settlement agreement in its entirety and it was executed by the parties. The settlement agreement includes a contribution by UI of $5 million and provides customers rate credits of $50 million while allowing UI to collect $52 million in RAM, all over a 22-month period ending April 2023 and also includes a distribution base rate freeze through April 2023. Pursuant to the legislation, PURA opened a docket to consider the implementation of the associated customer compensation and reimbursement provisions in emergency events where customers were without power for more than 96 consecutive hours. On June 30, 2021, PURA issued a final decision implementing the legislative mandate to create a program pursuant to which residential customers will receive $25 for each day without power after 96 hours and also receive reimbursement of $250 for spoiled food and medicine. The decision emphasizes that no costs incurred in connection with this program are recoverable from customers. The Company is reviewing the requirements of this program and evaluating next steps. PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation On August 6, 2020, the PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15-basis point reduction to UI’s ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. On June 11, 2021, UI filed an appeal of PURA's decision with the Connecticut Superior Court. On May 6, 2021, in connection with its findings in the Storm Isaias Docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. We cannot predict the outcome of these appeals. Regulatory Assets and Liabilities The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment. Regulatory assets as of September 30, 2021 and December 31, 2020, respectively, consisted of: September 30, December 31, As of 2021 2020 (Millions) Pension and other post-retirement benefits $ 814 $ 927 Pension and other post-retirement benefits cost deferrals 100 105 Storm costs 453 451 Rate adjustment mechanism 41 33 Revenue decoupling mechanism 53 58 Transmission revenue reconciliation mechanism 38 31 Contracts for differences 77 86 Hardship programs 22 20 Plant decommissioning 2 3 Deferred purchased gas 22 30 Deferred transmission expense 11 26 Environmental remediation costs 263 247 Debt premium 77 83 Unamortized losses on reacquired debt 23 26 Unfunded future income taxes 401 373 Federal tax depreciation normalization adjustment 144 148 Asset retirement obligation 21 21 Deferred meter replacement costs 42 33 COVID-19 cost recovery 20 1 Other 216 180 Total regulatory assets 2,840 2,882 Less: current portion 340 310 Total non-current regulatory assets $ 2,500 $ 2,572 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Storm costs” for CMP, NYSEG, RG&E and UI are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. A portion of this balance is amortized through current rates, and the remaining portion will be determined through future rate cases. “Rate adjustment mechanism” represents an interim rate change to return or collect certain defined reconciled revenues and costs for NYSEG and RG&E. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve-month period. “Reliability support services” represents the difference between actual expenses for reliability support services and the amount provided in rates. "Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales. "Transmission revenue reconciliation mechanism" reflects differences in actual costs in the rate year from those used to set rates. This mechanism contains the Annual Transmission True up (ATU), which is recovered over the subsequent June to May period. “Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability. “Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates. “Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates. “Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements. “Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending associated with allowable costs is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base. “Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments. “Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt. “Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow-through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant-related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. These amounts are being collected over a period of forty-six years, and the NYPSC staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances. “Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rate years covering 2011 forward. The recovery period in New York is from 25 to 35 years and for CMP 32.5 years beginning in 2020. “Asset retirement obligations” (ARO) represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced or are planned to be replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters. "COVID-19 cost recovery" represents deferred COVID-19-related costs in the states of Connecticut and New York. “Other” includes various items subject to reconciliation including excess generation service charge, rate change levelization and deferred property tax. Regulatory liabilities as of September 30, 2021 and December 31, 2020, respectively, consisted of: September 30, December 31, As of 2021 2020 (Millions) Energy efficiency portfolio standard $ 46 $ 58 Gas supply charge and deferred natural gas cost 3 3 Pension and other post-retirement benefits cost deferrals 49 59 Carrying costs on deferred income tax bonus depreciation 27 34 Carrying costs on deferred income tax - Mixed Services 263A 8 11 2017 Tax Act 1,366 1,435 Rate Change Levelization 98 55 Revenue decoupling mechanism 20 9 Accrued removal obligations 1,195 1,184 Asset sale gain account 3 7 Economic development 28 28 Positive benefit adjustment 24 30 Theoretical reserve flow thru impact 7 10 Deferred property tax 24 31 Net plant reconciliation 17 20 Debt rate reconciliation 53 63 Rate refund – FERC ROE proceeding 35 33 Transmission congestion contracts 22 22 Merger-related rate credits 12 14 Accumulated deferred investment tax credits 24 25 Asset retirement obligation 18 18 Earning sharing provisions 14 17 Middletown/Norwalk local transmission network service collections 17 18 Low income programs 29 28 Non-firm margin sharing credits 20 14 New York 2018 winter storm settlement 6 9 Hedge gains 88 — Other 168 176 Total regulatory liabilities 3,421 3,411 Less: current portion 367 274 Total non-current regulatory liabilities $ 3,054 $ 3,137 “Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. "Gas supply charge and deferred natural gas cost" reflects the actual costs of purchasing, transporting and storing of natural gas. Gas supply reconciliation is determined by comparing actual gas supply expenses to the monthly gas cost recoveries in rates. Prior rate year balances are collected/returned to customers beginning the next calendar year. “Pension and other postretirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. "Carrying costs on deferred income tax - Mixed Services 263A" represent the carrying costs benefit of increased accumulated deferred income taxes created by IRC Section 263A. 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 resulted 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 instituted separate proceedings in New York, Maine, Connecticut and Massachusetts, respectively, that addressed the implications associated with the Tax Act on the utilities providing service in such states. "Rate change levelization" adjusts the New York delivery rate increases across the three-year plan to avoid unnecessary spikes and offsetting dips in customer rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020. "Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales. “Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant. “Asset sale gain account” represents the net gain on the sale of certain assets that will be used for the future benefit of customers. The amortization period in current rates is three years for NYSEG and two years for RG&E and began in 2020. “Economic development” represents the economic development program, which enables NYSEG and RG&E to foster economic development through attraction, expansion and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to customers. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. “Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow- through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three "Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided 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 include interest, commissions and fees versus amounts included in rates. "Rate refund - FERC ROE proceeding" represents the reserve associated with the FERC proceeding around the base return on equity (ROE) reflected in ISO New England, Inc.’s (ISO-NE) open access transmission tariff (OATT). See Note 8 for more details. "Transmission congestion contracts" represents deferral of the Nine Mile 2 Nuclear Plant transmission congestion contract at RG&E. A portion of this balance is amortized through current rates; the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During both the three and nine months ended September 30, 2021 and 2020, $1 million and $2 million, respectively, of rate credits were applied against customer bills. "Asset retirement obligation" represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability . "Earning sharing provisions" represents the annual earnings over the earnings sharing threshold. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. "Middletown/Norwalk local transmission network service collections" represents allowance for funds used during construction of the Middletown/Norwalk transmission line, which is being amortized over the useful life of the project. “Low income programs” represent various hardship and payment plan programs approved for recovery. "New York 2018 winter storm settlement" represents the settlement amount with the NYPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. The balance is being amortized through current rates over a period of three years, ending in 2023. "Hedge gains" represents the deferred fair value gains on electric and gas hedge contracts. “Other” includes cost of removal being amortized through rates and various items subject to reconciliation.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	9 Months Ended
	Sep. 30, 2021
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments and Fair Value Measurements	Fair Value of Financial Instruments and Fair Value Measurements We determine the fair value of our derivative assets and liabilities and non-current equity investments associated with Networks’ activities utilizing market approach valuation techniques: • Our equity and other investments consist of Rabbi Trusts for deferred compensation plans and a supplemental retirement benefit life insurance trust. The Rabbi Trusts primarily include equity securities, fixed income and money market funds. We measure the fair value of our Rabbi Trust portfolio using observable, unadjusted quoted market prices in active markets for identical assets and include the measurements in Level 1. We measure the fair value of the supplemental retirement benefit life insurance trust based on quoted prices in the active markets for the various funds within which the assets are held and include the measurement in Level 2. • NYSEG and RG&E enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the NYISO. NYSEG and RG&E hedge approximately 70% of their electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value the companies’ open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value measurements in Level 1. • NYSEG and RG&E enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange (NYMEX). We include the fair value measurements in Level 1 because we use prices quoted in an active market . • NYSEG, RG&E and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used, but because an unobservable basis adjustment is added to the forward prices, we include the fair value measurement for these contracts in Level 3. • UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs). We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical products with no adjustment are included in fair value Level 1. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX, foreign exchange swaps, and fixed price physical and basis and index trades are included in fair value Level 2. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in fair value Level 3. The unobservable inputs include historical volatilities and correlations for tolling arrangements and extrapolated values for certain power swaps. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. We determine the fair value of our interest rate derivative instruments based on a model whose inputs are observable, such as the London Interbank Offered Rate (LIBOR) forward interest rate curves. We include the fair value measurement for these contracts in Level 2 (See Note 7 for further discussion of interest rate contracts). We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2. The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate fair value. Restricted cash was $4 million as of both September 30, 2021 and December 31, 2020, and is included in "Other Assets" on our condensed consolidated balance sheets. The financial instruments measured at fair value as of September 30, 2021 and December 31, 2020, respectively, consisted of: As of September 30, 2021 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 39 $ 16 $ — $ — $ 55 Derivative assets Derivative financial instruments - power $ 69 $ 37 $ 118 $ (73) $ 151 Derivative financial instruments - gas 24 64 15 (73) 30 Contracts for differences — — 2 — 2 Derivative financial instruments – Other — 4 1 — 5 Total $ 93 $ 105 $ 136 $ (146) $ 188 Derivative liabilities Derivative financial instruments - power $ (5) $ (186) $ (116) $ 202 $ (105) Derivative financial instruments - gas — (39) (3) 38 (4) Contracts for differences — — (79) — (79) Derivative financial instruments – Other — (69) — — (69) Total $ (5) $ (294) $ (198) $ 240 $ (257) As of December 31, 2020 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 49 $ 14 $ — $ — $ 63 Derivative assets Derivative financial instruments - power $ 5 $ 31 $ 105 $ (54) $ 87 Derivative financial instruments - gas — 24 19 (35) 8 Contracts for differences — — 2 — 2 Total $ 5 $ 55 $ 126 $ (89) $ 97 Derivative liabilities Derivative financial instruments - power $ (23) $ (31) $ (23) $ 72 $ (5) Derivative financial instruments - gas (1) (9) (2) 9 (3) Contracts for differences — — (88) — (88) Total $ (24) $ (40) $ (113) $ 81 $ (96) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and nine months ended September 30, 2021 and 2020, respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2021 2020 2021 2020 Fair Value Beginning of Period, $ (20) $ 16 $ 13 $ 25 Gains recognized in operating revenues 5 2 40 10 (Losses) recognized in operating revenues (14) — (33) (4) Total gains recognized in operating revenues (9) 2 7 6 Gains recognized in OCI — — 1 2 (Losses) recognized in OCI (18) (1) (65) (7) Total (losses) recognized in OCI (18) (1) (64) (5) Net change recognized in regulatory assets and liabilities 4 3 9 2 Purchases (14) (1) (18) — Settlements (4) (1) (8) (9) Transfers out of Level 3 (a) (1) (1) (1) (2) Fair Value as of September 30, $ (62) $ 17 $ (62) $ 17 Gains for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ (9) $ 2 $ 7 $ 6 (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. For the Nine Months Ended September 30, 2021 Index Avg. Max. Min. NYMEX ($/MMBtu) $ 2.98 $ 6.06 $ 2.27 AECO ($/MMBtu) $ 2.27 $ 7.40 $ (0.15) Ameren ($/MWh) $ 29.69 $ 81.39 $ 18.01 COB ($/MWh) $ 44.30 $ 231.90 $ 9.15 ComEd ($/MWh) $ 27.36 $ 75.88 $ 14.98 ERCOT N hub ($/MWh) $ 33.09 $ 140.00 $ 13.66 ERCOT S hub ($/MWh) $ 32.46 $ 140.00 $ 13.88 Indiana hub ($/MWh) $ 31.70 $ 83.18 $ 20.74 Mid C ($/MWh) $ 40.78 $ 229.90 $ 5.15 Minn hub ($/MWh) $ 26.34 $ 80.38 $ 15.23 NoIL hub ($/MWh) $ 27.12 $ 75.76 $ 14.64 PJM W hub ($/MWh) $ 30.61 $ 96.94 $ 17.78 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 uncontracted wind positions. The power swaps are used to hedge uncontracted wind production in the West and Midwest. We considered the measurement uncertainty regarding Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years. The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The gas swaps are economic hedges of uncontracted generation, with decreases in gas prices resulting in unrealized gains and increases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity. Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the models themselves. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products. Transactions are valued in part on the basis of forward price, correlation and volatility curves. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction. The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extends over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input September 30, 2021 Risk of non-performance 0.39% - 0.53% Discount rate 0.53% - 0.98% Forward pricing ($ per KW-month) $2.00 - $4.80 Fair Value of Debt As of September 30, 2021 and December 31, 2020, debt consisted of the Iberdrola Loan (see Note 14), first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. As of September 30, 2021 and December 31, 2020, the estimated fair value of debt was $8,800 million and $12,166 million, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the credit ratings of the borrowers in each case. All debt is considered Level 2 within the fair value hierarchy.

Derivative Instruments and Hedg

Derivative Instruments and Hedging	9 Months Ended
	Sep. 30, 2021
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 condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities. (a) Networks activities The tables below present Networks' derivative positions as of September 30, 2021 and December 31, 2020, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets: As of September 30, 2021 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 86 $ 8 $ 1 $ 4 Derivative liabilities (1) (4) (14) (68) 85 4 (13) (64) Designated as hedging instruments Derivative assets 1 — — — Derivative liabilities — — (3) — 1 — (3) — Total derivatives before offset of cash collateral 86 4 (16) (64) Cash collateral receivable — — — — Total derivatives as presented in the balance sheet $ 86 $ 4 $ (16) $ (64) 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) The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of September 30, 2021 and December 31, 2020, respectively, consisted of: September 30, December 31, As of 2021 2020 (Millions) Wholesale electricity purchase contracts (MWh) 5.6 5.6 Natural gas purchase contracts (Dth) 9.4 9.5 Fleet fuel purchase contracts (Gallons) 2.7 2.5 Derivatives not designated as hedging instruments NYSEG and RG&E have an electric commodity charge that passes costs for the market price of electricity through rates. We use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations. NYSEG and RG&E have purchased gas adjustment clauses that allow us to recover through rates any changes in the market price of purchased natural gas, substantially eliminating our exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities in accordance with the accounting requirements for regulated operations. The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of September 30, 2021 and December 31, 2020 and amounts reclassified from regulatory assets and liabilities into income for the three and nine months ended September 30, 2021 and 2020 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of Three Months Ended September 30, Nine Months Ended September 30, September 30, 2021 Electricity Natural Gas 2021 Electricity Natural Gas Electricity Natural Gas Regulatory assets $ — $ — Purchased power, natural gas and fuel used $ (18) $ — $ (8) $ (1) Regulatory liabilities $ (64) $ (24) December 31, 2020 2020 Regulatory assets $ 17 $ 1 Purchased power, natural gas and fuel used $ 8 $ — $ 41 $ 5 Pursuant to a PURA order, UI and Connecticut’s other electric utility, The Connecticut Light and Power Company (CL&P), each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers. PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of September 30, 2021, UI has recorded a gross derivative asset of $2 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $77 million, a gross derivative liability of $79 million ($76 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. As of December 31, 2020, UI had recorded a gross derivative asset of $2 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $86 million, a gross derivative liability of $88 million ($85 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three and nine months ended September 30, 2021 and 2020, respectively, were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Millions) Derivative assets $ — $ — $ — $ — Derivative liabilities $ 4 $ 3 $ 9 $ 2 Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ — Interest expense $ 1 $ 70 Foreign currency exchange contracts (1) — Total $ (1) $ 1 2020 Interest rate contracts $ — Interest expense $ 1 $ 86 Commodity contracts (1) Purchased power, natural gas and fuel used — 259 Total $ (1) $ 1 Nine Months Ended September 30, Gain (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) 2021 Interest rate contracts $ — Interest expense $ 3 $ 218 Commodity contracts 1 Purchased power, natural gas and fuel used — 1,085 Foreign currency exchange contracts (4) — Total $ (3) $ 3 2020 Interest rate contracts $ — Interest expense $ 3 $ 251 Commodity contracts (2) Purchased power, natural gas and fuel used 1 999 Foreign currency exchange contracts (2) — Total $ (4) $ 4 (a) Changes in accumulated OCI are reported on a pre-tax basis. As of September 30, 2021 and December 31, 2020, the net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization was $48 million and $51 million, respectively. Networks recorded net derivative losses related to discontinued cash flow hedges of $1 million and $3 million, for the three and nine months ended September 30, 2021, respectively, and $1 million and $3 million for the three and nine months ended September 30, 2020, respectively. Networks will amortize approximately $1 million of discontinued cash flow hedges for the remainder of 2021. As of September 30, 2021, unrealized losses of $3 million on hedge derivatives are reported in OCI because the forecasted transactions are considered to be probable. Networks expects $0 of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which Networks hedges its exposure to the variability in future cash flows for forecasted fleet fuel transactions is 12 months. (b) Renewables activities Renewables sells fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. Renewables also purchases fixed-price gas and basis swaps and sells fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets and enters into tolling arrangements to sell the output of its thermal generation facilities. Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets. Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed-price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed-price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms. The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of September 30, 2021 and December 31, 2020, respectively, consisted of: September 30, December 31, As of 2021 2020 (MWh/Dth in millions) Wholesale electricity purchase contracts 4 3 Wholesale electricity sales contracts 10 7 Natural gas and other fuel purchase contracts 22 24 Financial power contracts 10 12 Basis swaps – purchases 36 35 Basis swaps – sales 2 2 The fair values of derivative contracts associated with Renewables' activities as of September 30, 2021 and December 31, 2020, respectively, consisted of: September 30, December 31, As of 2021 2020 (Millions) Wholesale electricity purchase contracts $ 68 $ 4 Wholesale electricity sales contracts (131) 11 Natural gas and other fuel purchase contracts 2 — Financial power contracts 45 66 Basis swaps – purchases — 7 Total $ (16) $ 88 On May 27, 2021, Renewables entered into a forward interest rate swap, with a total notional amount of $935 million, to hedge the issuance of forecasted variable rate debt. The forward interest rate swap is designated and qualifies as a cash flow hedge. As part of the financial close of Vineyard Wind 1 described in Note 19, this hedge was novated to the lending institutions and the notional value changed to $956 million. As of September 30, 2021, the fair value of the interest rate swap was a $50 million non-current liability. The gain or loss on the interest rate swap is reported as a component of accumulated OCI and will be reclassified into earnings in the period or periods during which the related interest expense on the debt is incurred. The tables below present Renewables' derivative positions as of September 30, 2021 and December 31, 2020, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets: As of September 30, 2021 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 48 $ 80 $ 82 $ 17 Derivative liabilities (15) (10) (121) (21) 33 70 (39) (4) Designated as hedging instruments Derivative assets — — 2 5 Derivative liabilities (8) — (91) (128) (8) — (89) (123) Total derivatives before offset of cash collateral 25 70 (128) (127) Cash collateral (payable) receivable (1) — 50 45 Total derivatives as presented in the balance sheet $ 24 $ 70 $ (78) $ (82) 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) Derivatives not designated as hedging instruments The effects of trading and non-trading derivatives associated with Renewables' activities for the three and nine months ended September 30, 2021, consisted of: Three Months Ended September 30, 2021 Nine Months Ended September 30, 2021 Trading Non-trading Total amount per income statement Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (6) $ 3 $ 8 $ 2 Wholesale electricity sales contracts (8) (16) (8) (53) Financial power contracts 14 (6) 5 (62) Financial and natural gas contracts (2) (22) (2) (39) Total (loss) gain included in operating revenues $ (2) $ (41) $ 1,598 $ 3 $ (152) $ 5,041 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 18 $ — $ 55 Financial power contracts — (5) — 1 Financial and natural gas contracts — 21 — 44 Total gain included in purchased power, natural gas and fuel used $ — $ 34 $ 319 $ — $ 100 $ 1,085 Total (Loss) Gain $ (2) $ (7) $ 3 $ (52) The effects of trading and non-trading derivatives associated with Renewables' activities for the three and nine months ended September 30, 2020, consisted of: Three Months Ended September 30, 2020 Nine Months Ended September 30, 2020 Trading Non-trading Total amount per income statement Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 3 $ — $ 1 $ — Wholesale electricity sales contracts (7) (11) (1) 4 Financial power contracts 4 (12) 1 2 Financial and natural gas contracts — (8) — (13) Total (loss) gain included in operating revenues $ — $ (31) $ 1,470 $ 1 $ (7) $ 4,651 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 9 $ — $ (2) Financial power contracts — 1 — — Financial and natural gas contracts — 16 — 19 Total gain included in purchased power, natural gas and fuel used $ — $ 26 $ 259 $ — $ 17 $ 999 Total (Loss) Gain $ — $ (5) $ 1 $ 10 Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Loss Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ (18) Interest expense $ — $ 70 Commodity contracts (78) Operating revenues 1 $ 1,598 Total $ (96) $ 1 2020 Commodity contracts $ (17) Operating revenues $ 5 $ 1,470 Nine Months Ended September 30, Loss Recognized in OCI on Derivatives (a) Location of Gain Reclassified from Accumulated OCI into Income (Gain) Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ (50) Interest expense $ — $ 218 Commodity contracts (170) Operating revenues (5) $ 5,041 Total $ (220) $ (5) 2020 Commodity contracts $ (9) Operating revenues $ 4 $ 4,651 (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 $94 million of losses included in accumulated OCI at September 30, 2021, are expected to be reclassified into earnings within the next twelve months. For all of the three and nine months ended September 30, 2021 and 2020, we did not record any net derivative losses related to discontinued cash flow hedges. (c) Corporate activities AVANGRID uses financial derivative instruments from time to time to alter its fixed and floating rate debt balances or to hedge fixed rates in anticipation of future fixed rate issuances. As of September 30, 2021 and December 31, 2020, the net loss in accumulated OCI related to previously settled interest rate contracts was $50 million and $57 million, respectively. For the three and nine months ended September 30, 2021, we amortized into income $2 million and $7 million, respectively, and $2 million and $5 million, respectively, for the three and nine months ended September 30, 2020 of the loss related to settled interest rate contracts. We will amortize approximately $2 million of the net loss on the interest rate contracts for the remainder of 2021. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ — Interest expense $ 2 $ 70 2020 Interest rate contracts $ — Interest expense $ 2 $ 86 Nine Months Ended September 30, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ — Interest expense $ 7 $ 218 2020 Interest rate contracts $ (27) Interest expense $ 5 $ 251 (a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods which end in 2025 and 2029. On July 15, 2021, Corporate entered into an interest rate swap to hedge the fair value of $750 million of existing debt included in "Non-current debt" on our condensed consolidated balance sheets. The interest rate swap is designated and qualifies as a fair value hedge. The change in the fair value of the interest rate swap and the offsetting change in the fair value of the underlying debt are reported as components of "Interest expense." The effects on our condensed consolidated financial statements as of and for the three and nine months ended September 30, 2021 are as follows: (millions) Fair value of hedge Location of (Gain) Recognized in Income (Gain) Recognized in Income Year to date total per Income Statement As of September 30 ,2021 Three Months Ended September 30, 2021 Nine Months Ended September 30, 2021 Current Assets $ 4 Interest expense $ (1) $ (1) $ 218 Non-current liabilities $ (17) Cumulative effect on hedged debt Current debt $ (4) Non-current debt $ 17 (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 ratings on senior debt were to fall below investment grade. If such an event had occurred as of September 30, 2021, UI would have had to post an aggregate of approximately $14 million in collateral. We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of a default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. As of September 30, 2021 and December 31, 2020, the amount of cash collateral under master netting arrangements that have not been offset against net derivative positions was $55 million and $18 million, respectively. Derivative instruments settlements and collateral payments are included throughout the “Changes in operating assets and liabilities” section of operating activities in our condensed consolidated statements of cash flows. Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all

Contingencies and Commitments

Contingencies and Commitments	9 Months Ended
	Sep. 30, 2021
Commitments and Contingencies Disclosure [Abstract]
Contingencies and Commitments	Contingencies and Commitments We are party to various legal disputes arising as part of our normal business activities. We assess our exposure to these matters and record estimated loss contingencies when a loss is probable and can be reasonably estimated. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency. Transmission - ROE Complaint – CMP and UI On September 30, 2011, the Massachusetts Attorney General, DPU, PURA, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a joint complaint with the FERC pursuant to sections 206 and 306 of the Federal Power Act, against several New England Transmission Owners (NETOs) claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE with refunds to customers for the 15-month refund periods beginning October 1, 2011 (Complaint I), December 27, 2012 (Complaint II), July 31, 2014 (Complaint III) and April 29, 2016 (Complaint IV). On October 16, 2014, the FERC issued its decision in Complaint I, setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners. CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $27 million and $8 million, respectively, as of September 30, 2021, which has not changed since December 31, 2020, except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge would be an additional aggregate reserve for Complaints II and III of $17 million, which is based upon currently available information for these proceedings. Following various intermediate hearings, orders and appellate decisions, on October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs’ transmission formula rate on file at the FERC (the October 2018 Order). Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019 and replied to the initial briefs on March 8, 2019. On November 21, 2019, the FERC issued rulings on two complaints challenging the base return on equity for Midcontinent Independent System Operator, or MISO transmission owners. These rulings established a new zone of reasonableness based on equal weighting of the DCF and capital-asset pricing model for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing on this decision, which was granted. On May 21, 2020, FERC issued a ruling, which, among other things, adjusted the methodology to determine the MISO transmission owners’ ROE, resulting in an increase in ROE from 9.88% to 10.02% by utilizing the risk premium model in addition to the DCF model and capital-asset pricing model under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. On November 19, 2020, FERC issued an order addressing arguments raised on rehearing of its May 21, 2020 order, making minor adjustments to certain typographical errors with regard to some of the case inputs it included in its Risk Premium model analysis. However, those minor adjustments did not affect the outcome of the case, leaving the 10.02% ROE established by the May 21, 2020 order in place. Parties to these orders affecting the MISO transmission owners’ base ROE petitioned for their review at the D.C. Circuit Court of Appeals in January 2021. The NETO’s submitted an amici curia brief in support of the MISO transmission owners’ on March 17, 2021. We cannot predict the outcome of these proceedings, including the potential impact the MISO transmission owners' ROE proceeding may have in establishing a precedent for our pending four Complaints. On April 15, 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (Supplemental NOPR) that proposes to eliminate the 50 basis-point ROE incentive for utilities who join Regional Transmission Organizations after 3 years of membership. The NETOs submitted initial comments in opposition to the Supplemental NOPR on June 25, 2021. Reply comments are due on July 26, 2021. If the elimination of the 50 basis-point ROE incentive adder becomes final, we estimate we would have an approximately $3 million reduction in earnings per year. We cannot predict the outcome of this proceeding. California Energy Crisis Litigation Two California agencies brought a complaint in 2001 against a long-term power purchase agreement entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the power purchase agreement were unjust and unreasonable. The FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed the FERC's dismissal of Renewables from the proceeding. Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate court for further consideration in light of the Supreme Court’s decision in a similar case. In light of the Supreme Court's order, on December 4, 2008, the Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the Supreme Court's rulings. In 2014, the FERC assigned an administrative law judge to conduct evidentiary hearings. Following discovery, the FERC trial staff recommended that the complaint against Renewables be dismissed. A hearing was held before a FERC administrative law judge in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016. The proposed ruling found no evidence that Renewables had engaged in any unlawful market conduct that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that the price of the power purchase agreements imposed an excessive burden on customers in the amount of $259 million. Renewables position, as presented at hearings and agreed by the FERC trial staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted briefs on exceptions to the administrative law judge’s proposed ruling to the FERC. 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. On June 17, 2021, the FERC issued an Order Establishing Limited Remand remanding the case to the administrative law judge for additional detailed findings and legal analysis with respect to the impact of the conduct of one of the parties other than Renewables on their long-term contracts. The order did not address any of the other findings, including all of the findings with respect to Renewables, which remain pending. There is no specific timetable for the administrative law judge’s ruling. On July 9, 2021, Renewables filed a motion requesting that the FERC expeditiously issue a final decision with respect to the Avangrid Renewables long-term contract rather than waiting for the administrative law judge’s ruling. We cannot predict the outcome of this proceeding. New York State Public Service Commission Show Cause Order Regarding Greenlight Pole Attachments On November 20, 2020, the NYPSC issued an Order Instituting Proceeding and to Show Cause (the Show Cause Order) regarding alleged violations of the NYPSC’s 2004 Order Adopting Policy Statement on Pole Attachments, dated August 6, 2004 (the 2004 Pole Order) by RG&E, Greenlight Networks, Inc, (Greenlight), and Frontier Communications (Frontier). The alleged violations detailed in the Show Cause Order arise from Greenlight’s installation of unauthorized and substandard communications attachments throughout RG&E’s and Frontier’s service territories. The Show Cause Order directs RG&E to show cause within 30 days why the NYPSC should not pursue civil and/or administrative penalties or initiate a prudency proceeding or civil action for injunctive relief for more than 11,000 alleged violations of the 2004 Pole Order. Under NY Public Service Law Section 25-a, each alleged violation carries a potential penalty of up to $100,000 where it can be shown that the violator failed to “reasonably comply” with a statute or NYPSC order. RG&E, Greenlight and Frontier filed respective notices to initiate settlement negotiations with respect to the alleged violations and to extend the deadline for filing a response to the Show Cause Order. The NYPSC granted the extension requests initiating settlement discussions. On or about August 12, 2021, the NYPSC approved a settlement entered into by NYDPS and RG&E providing for, among other things, RG&E’s payment of $3 million, which will be used to support the State of New York’s broadband initiative for underserved areas. This settlement amount could increase to a maximum of $5 million if RG&E does not resolve certain identified safety violations caused by Greenlight’s pole attachments on or before December 31, 2021. We have met all compliance requirements of the settlement and expect to file with the NYPSC in the fourth quarter of 2021. We cannot predict the final outcome of this matter. Beatrice Corwin Living Irrevocable Trust, by and through Its Authorized Trustee, Robert Corwin v. Iberdrola, S.A., et. al. On January 8, 2021, the Beatrice Corwin Living Irrevocable Trust, by and through its Authorized Trustee, Robert Corwin filed a complaint in the Supreme Court of the State of New York Westchester County against Iberdrola and the members of the Company’s Board of Directors, as defendants, and the Company, as a nominal defendant with respect to certain counts contained in the complaint. The complaint alleges certain violations of fiduciary duties by Iberdrola and the members of the Company’s Board of Directors related to the existence of certain pre-emptive rights provided to Iberdrola in the Shareholder Agreement between the Company and Iberdrola, dated December 16, 2015, and the binding nature of such rights. On March 29, 2021, the parties stipulated to and requested, and the Supreme Court of the State of New York Westchester County issued an Order providing for, the transfer of the venue of the complaint to the Supreme Court, County of New York. On May 20, 2021, the matter was transferred to New York County and assigned to the Commercial Division of the Supreme Court, County of New York. On September 3, 2021, the plaintiffs filed an amended verified complaint (i) dropping claims concerning the purported breach of AVANGRID’s articles of incorporation and New York’s statute concerning equal treatment among shareholders, (ii) adding and modifying their claims related to the duty of good faith and loyalty and (iii) adding allegations concerning the Iberdrola Loan and the May 2021 private placement of our common shares to Iberdrola and Hyde Partners, LLC. In addition, the plaintiffs are now purporting to bring a class action lawsuit. On October 22, 2021, we and our board of directors filed a motion to dismiss and Iberdrola filed a motion to dismiss and an application to stay discovery pending resolution of dispositive motions. We cannot predict the outcome of this matter. Guarantee Commitments to Third Parties As of September 30, 2021, we had approximately $474 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding, including $25 million related to Vineyard Wind. We also provided a guaranty related to Renewables' commitment to contribute equity to Vineyard Wind as described in Note 19. These instruments provide financial assurance to the business and trading partners of AVANGRID, its subsidiaries and equity method investees in their normal course of business. The instruments only represent liabilities if AVANGRID or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of September 30, 2021, neither we nor our subsidiaries have any liabilities recorded for these instruments. NECEC Commitments On January 4, 2021, CMP transferred the NECEC project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks, pursuant to the terms of a transfer agreement dated November 3, 2020. Among other things, NECEC Transmission LLC and/or CMP committed to approximately $90 million of future payments to support various programs in the state of Maine.

Environmental Liabilities

Environmental Liabilities	9 Months Ended
	Sep. 30, 2021
Environmental Remediation Obligations [Abstract]
Environmental Liabilities	Environmental Liabilities Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies. Waste sites The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-six waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-six sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; five sites are included in Maine’s Uncontrolled Sites Program; one site is included in the Brownfield Cleanup Program and one site is included on the Massachusetts Non-Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, six of the twenty-six sites are also included on the National Priorities list. Any liability may be joint and several for certain sites. We have recorded an estimated liability of $7 million related to eleven of the twenty-six sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $9 million related to another twelve sites where we believe it is probable that we will incur remediation and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. As of September 30, 2021, our estimate for costs to remediate these sites ranges from $15 million to $22 million. 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; and three sites are part of Maine’s Voluntary Response Action Program with two such sites part of Maine’s Uncontrolled Sites Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites. As of September 30, 2021, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $169 million to $282 million. 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; as of September 30, 2021, no liability was recorded related to these sites and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites. As of September 30, 2021 and December 31, 2020, the liability associated with our MGP sites in Connecticut was $114 million and $96 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. As of September 30, 2021 and December 31, 2020, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $310 million and $300 million, 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 2053. FirstEnergy NYSEG and RG&E each sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at certain former MGP sites, which are included in the discussion above. In 2011, the District Court issued a decision and order in NYSEG’s favor, which was upheld on appeal, requiring FirstEnergy to pay NYSEG for past and future clean-up costs at the sixteen sites in dispute. In 2008, the District Court issued a decision and order in RG&E favor requiring FirstEnergy to pay RG&E for past and future clean-up costs at the two MGP sites in dispute. FirstEnergy remains liable for a substantial share of clean up expenses at the MGP sites. Based on projections as of September 30, 2021, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $16 million and $7 million, respectively. These amounts are being treated as contingent assets and have not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG and RG&E customers, as applicable. English Station In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then owners of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut related to environmental remediation at the English Station site. This proceeding was stayed in 2014 pending resolutions of other proceedings before the Connecticut Department of Energy and Environmental Protection (DEEP) concerning the English Station site. In December 2016, the court administratively closed the file without prejudice to reopen upon the filing of a motion to reopen by any party. In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit related to the English Station site. On April 16, 2018, the plaintiffs filed a revised complaint alleging fraud and unjust enrichment against UIL and UI and adding former UIL officers as named defendants alleging fraud. On February 21, 2019, the court granted our Motion to Strike with respect to all counts except for the count against UI for unjust enrichment. The counts stricken include all counts against the individual defendants as well as against UIL. The plaintiffs appealed the court's decision to strike. On May 4, 2021, the Appeals Court affirmed the court's decision striking the counts. The plaintiffs filed a petition to appeal to the Connecticut Supreme Court, which was denied, leaving only the claim against UI for unjust enrichment. 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 continued its process to investigate and remediate the environmental conditions within the perimeter of the English Station site pursuant to the consent order. As of both September 30, 2021 and December 31, 2020, the amount reserved related to English Station was $22 million. Since inception, we have recorded $35 million to the reserve which has been offset with cash payments over time.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. Arbitration for this matter has been scheduled for the fourth quarter of 2021. We cannot predict the outcome of this matter.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	9 Months Ended
	Sep. 30, 2021
Retirement Benefits [Abstract]
Post-retirement and Similar Obligations	Post-retirement and Similar Obligations During the three and nine months ended September 30, 2021, we made $13 million and $27 million, respectively, of pension contributions. We expect to make additional contributions of $48 million for the remainder of 2021. The components of net periodic benefit cost for pension benefits for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Millions) Service cost $ 10 $ 12 $ 30 $ 35 Interest cost 22 27 66 81 Expected return on plan assets (50) (50) (151) (150) Amortization of: Prior service costs — — 1 — Actuarial loss 29 31 88 94 Net Periodic Benefit Cost $ 11 $ 20 $ 34 $ 60 The components of net periodic benefit cost for postretirement benefits for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Millions) Service cost $ 1 $ 1 $ 2 $ 2 Interest cost 2 4 7 10 Expected return on plan assets (2) (2) (5) (6) Amortization of: Prior service costs (1) (3) (4) (7) Actuarial loss — — 1 1 Net Periodic Benefit Cost $ — $ — $ 1 $ —

Equity

Equity	9 Months Ended
	Sep. 30, 2021
Equity [Abstract]
Equity	Equity As of September 30, 2021 and December 31, 2020, we had 116,928 and 413,782 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the three and nine months ended September 30, 2021, we released 0 and 292,594 shares of common stock held in trust, respectively. During the three and nine months ended September 30, 2020, we released 0 and 213 shares of common stock held in trust, respectively. See Note 1 for information on our May 2021 equity issuance. We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain Iberdrola's relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In March 2021, 53,311 shares were repurchased pursuant to the stock repurchase program. As of September 30, 2021, a total of 357,146 shares have been repurchased in the open market, all of which are included as AVANGRID treasury shares. The total cost of all repurchases, including commissions, was $16 million as of September 30, 2021. Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: As of June 30, Three Months Ended September 30, As of September 30, As of June 30, Three Months Ended September 30, As of September 30, 2021 2021 2021 2020 2020 2020 (Millions) Change in revaluation of defined benefit plans $ (12) $ — $ (12) $ (12) $ — $ (12) Loss on nonqualified pension plans (20) — (20) (7) — (7) Unrealized loss from equity method investment, net of income tax expense of $1 for 2021 (a) (3) (6) (9) — — — Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(23) for 2021 and $(3) for 2020 (135) (73) (208) (29) (15) (44) Reclassification to net income of losses on cash flow hedges, net of income tax (benefit) expense of $(2) for 2021 and $0 for 2020 (b) (39) 5 (34) (60) 9 (51) (Loss) Gain on derivatives qualifying as cash flow hedges (174) (68) (242) (89) (6) (95) Accumulated Other Comprehensive Loss $ (209) $ (74) $ (283) $ (108) $ (6) $ (114) As of December 31, Nine Months Ended September 30, As of September 30, As of December 31, Nine Months Ended September 30, As of September 30, 2020 2021 2021 2019 2020 2020 (Millions) Change in revaluation of defined benefit plans $ (12) $ — $ (12) $ (12) $ — $ (12) Loss on nonqualified pension plans (20) — (20) (7) — (7) Unrealized loss from equity method investment, net of income tax benefit of $(3) for 2021 (a) $ — $ (9) $ (9) $ — $ — $ — Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(49) for 2021 and $(8) for 2020 (35) (173) (208) (13) (31) (44) Reclassification to net income of losses on cash flow hedges, net of income tax (benefit) expense of $(6) for 2021 and $1 for 2020 (b) (44) 10 (34) (63) 12 (51) (Loss) Gain on derivatives qualifying as cash flow hedges (79) (163) (242) (76) (19) (95) Accumulated Other Comprehensive Loss $ (111) $ (172) $ (283) $ (95) $ (19) $ (114) (a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization and line items in our condensed consolidated statements of income.

Earnings Per Share

Earnings Per Share	9 Months Ended
	Sep. 30, 2021
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the three and nine months ended September 30, 2021 and 2020, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculations. The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 111 $ 87 $ 543 $ 415 Denominator: Weighted average number of shares outstanding - basic 387,321,484 309,491,082 348,264,388 309,496,234 Weighted average number of shares outstanding - diluted 387,676,085 309,550,126 348,714,535 309,554,838 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.29 $ 0.28 $ 1.56 $ 1.34 Earnings Per Common Share, Diluted $ 0.29 $ 0.28 $ 1.56 $ 1.34

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2021
Segment Reporting [Abstract]
Segment Information	Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments: • Networks: includes all of the energy transmission and distribution activities, any other regulated activity originating in New York and Maine and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes nine rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment. • Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities. The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude restructuring charges, mark-to-market earnings from changes in the fair value of derivative instruments, accelerated depreciation derived from repowering of wind farms, costs incurred in connection with the COVID-19 pandemic and costs incurred related to the PNMR Merger. Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in our condensed consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment. Segment information as of and for the three and nine months ended September 30, 2021, consisted of: Three Months Ended September 30, 2021 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,357 $ 243 $ (2) $ 1,598 Revenue - intersegment — — — — Depreciation and amortization 156 103 — 259 Operating income (loss) 158 (18) (2) 138 Earnings (losses) from equity method investments 3 (4) — (1) Interest expense, net of capitalization 51 — 19 70 Income tax expense (benefit) 8 (26) (6) (24) Adjusted net income $ 130 $ 18 $ (15) $ 133 Nine Months Ended September 30, 2021 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 4,148 $ 894 $ (1) $ 5,041 Revenue - intersegment 1 — (1) — Depreciation and amortization 461 294 1 756 Operating income 618 58 (1) 675 Earnings (losses) from equity method investments 10 (6) — 4 Interest expense, net of capitalization 157 — 61 218 Income tax expense (benefit) 74 (56) (18) — Adjusted net income 467 182 (39) 609 Capital expenditures 1,512 385 — 1,897 As of September 30, 2021 Property, plant and equipment 18,206 9,943 9 28,158 Equity method investments 141 430 — 571 Total assets $ 25,930 $ 12,272 $ 677 $ 38,879 (a) Includes Corporate and intersegment eliminations. Segment information for the three and nine months ended September 30, 2020 and as of December 31, 2020, consisted of: Three Months Ended September 30, 2020 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,194 $ 275 $ 1 $ 1,470 Revenue - intersegment 3 1 (4) — Depreciation and amortization 151 104 — 255 Operating income 160 7 (2) 165 Earnings (losses) from equity method investments 3 (2) — 1 Interest expense, net of capitalization 63 (1) 24 86 Income tax expense (benefit) 20 (7) 2 15 Adjusted net income $ 99 $ 32 $ (31) $ 100 Nine Months Ended September 30, 2020 Networks Renewables Other (a) AVANGRID (Millions) Revenue - external $ 3,775 $ 875 $ 1 $ 4,651 Revenue - intersegment 4 1 (5) — Depreciation and amortization 446 301 1 748 Operating income 617 24 6 647 Earnings (losses) from equity method investments 8 (11) — (3) Interest expense, net of capitalization 199 (1) 53 251 Income tax expense (benefit) 75 (53) (1) 21 Adjusted net income 379 108 (53) 434 Capital expenditures 1,312 648 — 1,960 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. Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three and nine months ended September 30, 2021 and 2020, respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 133 $ 100 $ 609 $ 434 Adjustments: Mark-to-market earnings - Renewables (1) (9) (7) (50) 9 Restructuring charges (2) — (1) — (5) Accelerated depreciation from repowering (3) — (3) — (9) Impact of COVID-19 (4) (19) (8) (33) (21) Merger costs (5) (3) — (6) — Income tax impact of adjustments 8 5 24 7 Net Income Attributable to Avangrid, Inc. $ 111 $ 87 $ 543 $ 415 (1) Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas. (2) Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth. (3) Represents the amount of accelerated depreciation derived from repowering of wind farms in Renewables. (4) Represents costs incurred in connection with the COVID-19 pandemic. (5) Pre-merger costs incurred.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2021
Related Party Transactions [Abstract]
Related Party Transactions	Related Party TransactionsWe engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, 2021 2020 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Renovables Energía, S.L. $ — $ (3) $ — $ (2) Iberdrola Financiación, S.A. $ — $ (4) $ — $ (3) Iberdrola $ — $ (14) $ — $ (10) Vineyard Wind $ 4 $ — $ 3 $ — Iberdrola Solutions $ (1) $ — $ 2 $ — Other $ — $ (1) $ — $ (1) Nine Months Ended September 30, 2021 2020 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Renovables Energía, S.L. $ — $ (8) $ — $ (6) Iberdrola Financiación, S.A. $ — $ (7) $ — $ (5) Iberdrola $ — $ (41) $ — $ (31) Vineyard Wind $ 12 $ — $ 7 $ — Iberdrola Solutions $ 7 $ (39) $ 2 $ — Other $ 1 $ (2) $ — $ (2) Related party balances as of September 30, 2021 and December 31, 2020, respectively, consisted of: As of September 30, 2021 December 31, 2020 (Millions) Owed By Owed To Owed By Owed To Iberdrola $ 2 $ (34) $ 2 $ (43) Iberdrola Renovables Energía, S.L. $ — $ (8) $ — $ — Iberdrola Financiación, S.A. $ — $ (7) $ — $ (6) Vineyard Wind $ 5 $ — $ 4 $ — Iberdrola Solutions $ — $ (3) $ 5 $ — Other $ — $ — $ 1 $ (1) On December 14, 2020, AVANGRID and Iberdrola, our majority shareholder, entered into an intra-group loan agreement which provided AVANGRID with an unsecured subordinated loan in an aggregate principal amount of $3,000 million (the Iberdrola Loan). The Iberdrola Loan was repaid with the proceeds of the common share issuance described in Note 1. Other transactions with Iberdrola relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. See Note 1 for information on the Side Letter Agreement we entered into with Iberdrola. We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable and notes receivable balances of $2 million and $5 million, respectively, as of September 30, 2021 and December 31, 2020. Renewables also had financial forward power contracts with Iberdrola Solutions to hedge Renewables' uncontracted wind exposure in Texas. There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances. AVANGRID manages its overall liquidity position as part of the Iberdrola Group and is a party to a liquidity agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the liquidity agreement. The balance at both September 30, 2021 and December 31, 2020, was zero. AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of September 30, 2021 and December 31, 2020, there was no outstanding amount under this credit facility. See Note 19 - Equity Method Investments for more information on Vineyard Wind, LLC (Vineyard Wind).

Other Financial Statement Items

Other Financial Statement Items	9 Months Ended
	Sep. 30, 2021
Balance Sheet Related Disclosures [Abstract]
Other Financial Statement Items	Other Financial Statement Items Accounts receivable and unbilled revenue, net Accounts receivable and unbilled revenues, net as of September 30, 2021 and December 31, 2020 consisted of: As of September 30, 2021 December 31, 2020 (Millions) Trade receivables and unbilled revenues $ 1,279 $ 1,295 Allowance for credit losses (174) (108) Accounts receivable and unbilled revenues, net $ 1,105 $ 1,187 The change in the allowance for credit losses for the three and nine months ended September 30, 2021 and 2020 consisted of: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2021 2020 2021 2020 As of Beginning of Period, $ 150 $ 85 $ 108 $ 69 Current period provision 41 19 106 60 Write-off as uncollectible (17) (10) (40) (35) As of September 30, $ 174 $ 94 $ 174 $ 94 As of September 30, 2021 and December 31, 2020, our Deferred Payment Arrangements (DPA) receivable balance was $103 million and $78 million, respectively. As of September 30, 2021 and December 31, 2020, our allowance for credit losses for DPAs was $69 million and $48 million, respectively. For the three and nine months ended September 30, 2021, the change in our allowance for credit losses associated with our DPAs was $7 million and $21 million, respectively, and for the three and nine months ended September 30, 2020, was $3 million and $4 million, respectively. Prepayments and other current assets As of September 30, 2021 and December 31, 2020, prepayments and other current assets included prepaid other taxes of $231 million and $135 million, respectively. Property, plant and equipment and intangible assets The accumulated depreciation and amortization as of September 30, 2021 and December 31, 2020, respectively, were as follows: September 30, December 31, As of 2021 2020 (Millions) Property, plant and equipment Accumulated depreciation $ 10,421 $ 9,799 Intangible assets Accumulated amortization $ 329 $ 319 As of September 30, 2021 and 2020, accrued liabilities for property, plant and equipment additions were $367 million and $370 million, respectively. Debt See Note 19 for discussion of the credit agreement entered by Renewables in relation to one of its equity method investments. On September 24, 2021, NYSEG issued $350 million aggregate principal amount of unsecured notes maturing in 2031 at a fixed interest rate of 2.15%. As of September 30, 2021 and December 31, 2020, "Notes Payable" consisted of $0 and $309 million, respectively, of commercial paper outstanding, presented net of discounts on our condensed consolidated balance sheets. Our $500 million credit facility was scheduled to mature on June 28, 2021. We terminated this facility on April 28, 2021. We operate a number of supplier financing arrangements. During 2021, we arranged for the extension of payment terms with some suppliers, which could elect to be paid by a financial institution earlier than maturity under supplier financing arrangements. Due to the interest cost associated with these arrangements, the balances are classified as "Notes payable" on our condensed consolidated balance sheets. The balance relates to capital expenditures and, therefore, is treated as non-cash activity. As of September 30, 2021 and December 31, 2020, the amount of notes payable under supplier financing arrangements was $97 million and $0, respectively. As of September 30, 2021, the weighted average interest rate on the balance was 1.08%. Disposition On May 13, 2021, Renewables sold 100% of its ownership interest in two solar projects located in Nevada to Primergy Hot Pot Holdings LLC for total consideration of $35 million and recognized a gain of $3 million, net of tax. The pre-tax gain of $4 million is recorded in "Operating revenues" in our condensed consolidated statements of income. The total consideration includes variable consideration that Renewables could receive based on the achievement of certain regulatory and project development milestones. The transaction was accounted for as an asset sale.

Income Tax Expense

Income Tax Expense	9 Months Ended
	Sep. 30, 2021
Income Tax Disclosure [Abstract]
Income Tax Expense	Income Tax ExpenseThe effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2021, were (30.0)% and 0.0%, respectively. The effective tax rates for the three and nine months ended September 30, 2021, are below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act and the equity component of allowance for funds used during construction.The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2020, were 15.6% and 5.1%, respectively. The effective tax rates for the three and nine months ended September 30, 2020 are below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act.

Stock-Based Compensation Expens

Stock-Based Compensation Expense	9 Months Ended
	Sep. 30, 2021
Share-based Payment Arrangement [Abstract]
Stock-Based Compensation Expense	Stock-Based Compensation Expense The Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares). Performance Stock Units In February 2020, a total number of 208,268 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance metrics related to the 2016 through 2019 plan and are payable in three equal installments, net of applicable taxes. In March 2021, 45,661 shares of common stock were issued to settle the second installment payment. The final payment will occur in 2022. On February 15, 2021 and March 15, 2021, 1,181,031 and 75,000 PSUs, respectively, were granted to certain officers and employees of AVANGRID with achievement measured based on certain performance and market-based metrics for the 2021 to 2022 performance period. The PSUs will be payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The fair value of the PSUs on the grant date was $36.22 per share. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recently quarterly dividend payment and the stock price as of the grant date. The expense is recognized on a straight-line basis over the requisite service period of approximately four years based on expected achievement. Restricted Stock Units In October 2018, 8,000 RSUs were granted to an officer of AVANGRID. The RSUs vested in full in December 2020. The fair value on the grant date was determined based on a price of $47.59 per share. In March 2021, the RSU grant was settled, net of applicable taxes, by issuing 5,953 shares of common stock. In August 2020, 5,000 RSUs were granted to an officer of AVANGRID. The RSUs vest in three equal installments in 2021, 2022 and 2023, provided that the grantee remains continuously employed with AVANGRID through the applicable vesting dates. The fair value on the grant date was determined based on a price of $48.99 per share. In February 2021, the first installment of the RSU grant was settled by issuing 1,697 shares of common stock. In June 2021, 17,500 RSUs were granted to an officer of AVANGRID with immediate vesting. The fair value on the grant date was determined based on a price of $53.59 per share. The RSU grant was settled, net of applicable taxes, by issuing 9,390 shares of common stock. Phantom Share Units In March 2020, 167,060 Phantom Shares were granted to certain AVANGRID executives and employees. These awards vest in three equal installments in 2020, 2021 and 2022 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of AVANGRID’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of AVANGRID’s common stock at each reporting date until the date of settlement. In March 2021, $2 million was paid to settle the second installment under this plan. As of both September 30, 2021 and December 31, 2020, the total liability was $2 million, which is included in other current liabilities. Total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three and nine months ended September 30, 2021 was $5 and $14 million, respectively, and for the three and nine months ended September 30, 2020 was $1 million and $12 million, respectively.

Variable Interest Entities

Variable Interest Entities	9 Months Ended
	Sep. 30, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entities	Variable Interest Entities We participate in certain partnership arrangements that qualify as variable interest entities (VIEs). Consolidated VIE's consist of tax equity financing arrangements (TEFs) and partnerships in which an investor holds a noncontrolling interest and does not have substantive kick-out or participating rights. The sale of a membership interest in the TEFs represents the sale of an equity interest in a structure that is considered a sale of non-financial assets. Under the sale of non-financial assets, the membership interests in the TEFs we sell to third-party investors are reflected as noncontrolling interest on our condensed consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our condensed consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs. On February 5, 2021, we closed on the final TEF agreement for Aeolus Wind Power VII, LLC (Aeolus VII) in a non-cash transaction. The four Aeolus VII wind farms total 688 MW of wind power. On September 9, 2021, we sold an additional TEF interest in Aeolus VII for $131 million. The $8 million difference between the amount received and the $139 million noncontrolling interest recognized was recorded as an adjustment to equity because there was no change in control as a result of the transaction. The assets and liabilities of the VIEs totaled approximately $1,649 million and $72 million, respectively, at September 30, 2021. As of December 31, 2020, the assets and liabilities of VIEs totaled approximately $1,713 million and $107 million, respectively. At September 30, 2021 and December 31, 2020, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment. At September 30, 2021, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot) and Aeolus VII are our consolidated VIEs. Wind power generation is subject to certain favorable tax treatments in the U.S. In order to monetize the tax benefits, we have entered into these structured institutional partnership investment transactions related to certain wind farms. Under these structures, we contribute certain wind assets, relating both to existing wind farms and wind farms that are being placed into operation at the time of the relevant transaction, and other parties invest in the share equity of the limited liability holding company. As consideration for their investment, the third parties make either an upfront cash payment or a combination of upfront cash and payments over time. We retain a class of membership interest and day-to-day operational and management control, subject to investor approval of certain major decisions. The third-party investors do not receive a lien on any assets and have no recourse against us for their upfront cash payments. The partnerships generally involve disproportionate allocations of profit or loss, cash distributions and tax benefits resulting from the wind farm energy generation between the investor and sponsor until the investor recovers its investment and achieves a cumulative annual after-tax return. Once this target return is met, the relative sharing of profit or loss, cash distributions and taxable income or loss between the Company and the third-party investor flips, with the sponsor generally receiving higher percentages thereafter. We also have a call option to acquire the third-party investors’ membership interest within a defined time period after this target return is met. Our El Cabo, Patriot and Aeolus VII interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities associated with the interests. See Note 19 - Equity Method Investments for information on our VIE we do not consolidate.

Equity Method Investments

Equity Method Investments	9 Months Ended
	Sep. 30, 2021
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Equity Method Investments Renewables holds a 50% voting interest in a joint venture (Vineyard Wind) 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 (Vineyard Wind 1) and electricity transmission project pursuant to the Massachusetts Green Communities Act Section 83C RFP for offshore wind energy projects. In December 2019, DEEP selected Vineyard Wind to provide 804 MW of offshore wind through the development of its Park City Wind Project. Vineyard Wind acquired a second offshore easement contract from BOEM (Lease Area 522). 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 reimbursed Renewables $33 million, plus interest. On September 15, 2021, Vineyard Wind closed on construction financing for the Vineyard Wind 1 project. Concurrently, Renewables entered into a credit agreement with certain banks to provide future term loans and letters of credit up to a maximum of approximately $1.2 billion to finance a portion of its share of the cost of Vineyard Wind 1 at the maturity of the Vineyard Wind 1 project construction loan. Any term loans mature by October 15, 2031, subject to certain extension provisions. Renewables also entered into an Equity Contribution Agreement in which Renewables agreed to, among other things, make certain equity contributions to fund certain costs of developing and constructing the Vineyard Wind 1 project in accordance with the credit agreement. In addition, we issued a guaranty up to $827 million for Renewables' equity contributions under the Equity Contribution Agreement. As part of the Vineyard Wind 1 financial close, $136 million of Renewables prior contributions to Vineyard Wind were returned. On September 15, 2021, Renewables entered into an agreement with CIP to restructure Vineyard Wind. Pursuant to the restructuring agreement, Vineyard Wind 1 will remain a 50-50 joint venture, Renewables will take full ownership of the lease area which includes Park City Wind and Commonwealth Wind, the remaining non-contracted area in Lease Area 534, and CIP will take full ownership of Lease Area 522. The consideration exchanged will result in Renewables making a payment of approximately $168 million to CIP. The agreement is subject to certain customary closing conditions and is expected to close in the first quarter of 2022. 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 September 30, 2021 and December 31, 2020, the carrying amount of Renewables' investment in Vineyard Wind was $156 million and $245 million.

Significant Accounting Polici_2

Significant Accounting Policies and New Accounting Pronouncements (Policies)	9 Months Ended
	Sep. 30, 2021
Accounting Policies [Abstract]
Adoption of New Accounting Pronouncements and Accounting Pronouncements Issued but Not Yet Adopted	Adoption of New Accounting Pronouncements (a) Simplifying the accounting for income taxes In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes , eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation; (2) exceptions to accounting for basis differences in equity method investments when there are ownership changes in foreign investments; and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for: (1) franchise taxes that are partially based on income; (2) transactions with a government that result in a step up in the tax basis of goodwill; (3) separate financial statements of legal entities that are not subject to tax; and (4) enacted changes in tax laws in interim periods. We adopted the amendments effective January 1, 2021, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. We are applying the amendments on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment requirement. (b) Improvements to lessor accounting for certain leases with variable lease payments In July 2021, the FASB issued amendments to make targeted improvements to ASC 842 for lessor’s accounting for certain leases with variable lease payments, which affect lease classification. The amendments require a lessor to classify and account for a lease with variable lease payments as an operating lease if (a) the lease would have been classified as a sales-type lease or a direct financing lease and (b) the lessor would have otherwise recognized a day-one loss. The amendments are effective for fiscal years beginning after December 15, 2021, for all entities, and interim periods within those fiscal years for public business entities, with early application permitted. We have elected to early apply the amendments effective October 1, 2021, and apply the amendments prospectively to leases that commence or are modified on or after that date. Our adoption does not materially affect our consolidated results of operations, financial position and cash flows. Accounting Pronouncements Issued but Not Yet Adopted The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2020, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements. (a) Facilitation of the effects of reference rate reform on financial reporting, and subsequent scope clarification In March 2020, the FASB issued amendments and created ASC 848 to provide temporary optional guidance to entities to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments respond to concerns about structural risks of interbank offered rates, and particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR). The guidance is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform, around the end of 2021. The guidance applies to contracts that have modified terms that affect, or have the potential to affect, the amount or timing of contractual cash flows resulting from the discontinuance of the reference rate reform. The amendments are effective for all entities as of March 12, 2020, through December 31, 2022, although the FASB has indicated it will monitor developments in the marketplace and consider whether developments warrant an extension. In January 2021, the FASB issued amendments to clarify the scope of ASC 848 and respond to questions from stakeholders about whether ASC 848 can be applied to derivative instruments that do not reference a rate that is expected to be discontinued but that use an interest rate for margining, discounting, or contract price alignment that is modified because of reference rate reform. The modification, commonly referred to as the “discounting transition,” may have accounting implications, raising concerns about the need to reassess previous accounting determinations related to those derivatives and about the possible hedge accounting consequences of the discounting transition. The amendments clarify that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition, capture the incremental consequences of the scope clarification and tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments are effective immediately, and may be elected retrospectively to eligible modifications as of any date from the beginning of the interim period that includes March 12, 2020, or prospectively to new modifications made on or after any date within the interim period that includes January 7, 2021. We expect our adoption of reference rate reform and the subsequent scope clarification will not materially affect our consolidated results of operations, financial position and cash flows. (b) Accounting for revenue contracts with customers acquired in a business combination In October 2021, the FASB issued amendments related to the accounting for revenue contracts acquired in a business combination. The amendments require an entity (acquirer) to recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with ASC 606, Revenue from Contracts with Customers . At the acquisition date, an acquirer should account for the related revenue contract in accordance with ASC 606 as if it had originated the contracts. Generally, this should result in an acquirer recognizing and measuring the acquired contract assets and contract liabilities consistent with how they were recognized and measured in the acquiree’s financial statements. The amendments also provide certain practical expedients for acquirers when recognizing and measuring acquired contract assets and contract
Revenue Recognition	We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale. The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about our reportable segments, refer to Note 13. Networks Segment Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts, with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas. Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. We traditionally invoice our customers by applying approved base rates to usage. Maine state law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer. The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service. Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms (RDMs), other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives or ARPs. Renewables Segment Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all or a percentage of the unit’s output. Renewables also has unbundled sales of electric energy and capacity, RECs and natural gas, which are generally for periods of less than a year. The performance obligations in substantially all of both bundled and unbundled arrangements for electricity and natural gas are satisfied over time, for which we record revenue based on the amount invoiced to the customer for the actual energy delivered. The performance obligation for stand-alone RECs is satisfied at a point in time, for which we record revenue when the performance obligation is satisfied upon delivery of the REC. Renewables classifies certain contracts for the sale of electricity as derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of ASC 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other ASC 606 revenue, which we recognize based on the amount invoiced to the customer. Other Other, which does not represent a segment, includes miscellaneous Corporate revenues and intersegment eliminations. Contract Costs and Contract Liabilities We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in December 2021 upon commercial operation. At both September 30, 2021 and December 31, 2020, contract assets totaled $9 million and are presented in "Other non-current assets" on our condensed consolidated balance sheets.

Revenue (Tables)

Revenue (Tables)	9 Months Ended
	Sep. 30, 2021
Revenue from Contract with Customer [Abstract]
Schedule of Revenues Disaggregated by Major Source for Reportable Segments	For the three and nine months ended September 30, 2021 and 2020, revenues disaggregated by major source for our reportable segments are as follows: Three Months Ended September 30, 2021 Nine Months Ended September 30, 2021 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,105 $ — $ — $ 1,105 $ 2,959 $ — $ — $ 2,959 Regulated operations – natural gas 214 — — 214 1,034 — — 1,034 Nonregulated operations – wind — 205 — 205 — 819 — 819 Nonregulated operations – solar — 10 — 10 — 21 — 21 Nonregulated operations – thermal — 14 — 14 — 42 — 42 Other(a) 17 1 (2) 16 41 74 (2) 113 Revenue from contracts with customers 1,336 230 (2) 1,564 4,034 956 (2) 4,988 Leasing revenue 1 — — 1 6 — — 6 Derivative revenue — 22 — 22 — (72) — (72) Alternative revenue programs 8 — — 8 77 — — 77 Other revenue 12 (9) — 3 32 10 — 42 Total operating revenues $ 1,357 $ 243 $ (2) $ 1,598 $ 4,149 $ 894 $ (2) $ 5,041 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2020 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 984 $ — $ — $ 984 $ 2,701 $ — $ — $ 2,701 Regulated operations – natural gas 166 — — 166 910 — — 910 Nonregulated operations – wind — 200 — 200 — 639 — 639 Nonregulated operations – solar — 6 — 6 — 16 — 16 Nonregulated operations – thermal — 13 — 13 — 27 — 27 Other(a) 12 28 (4) 36 38 75 (4) 109 Revenue from contracts with customers 1,162 247 (4) 1,405 3,649 757 (4) 4,402 Leasing revenue 2 — — 2 5 — — 5 Derivative revenue — 25 — 25 — 111 — 111 Alternative revenue programs 24 — — 24 109 — — 109 Other revenue 9 4 1 14 16 8 — 24 Total operating revenues $ 1,197 $ 276 $ (3) $ 1,470 $ 3,779 $ 876 $ (4) $ 4,651 (a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate and intersegment eliminations.
Schedule of Aggregate Transaction Price Allocations	As of September 30, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of September 30, 2021 2022 2023 2024 2025 2026 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 6 $ 1 $ 1 $ — $ — $ — $ 8 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 26 18 14 12 10 65 145 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 39 23 10 3 3 2 80 Total operating revenues $ 71 $ 42 $ 25 $ 15 $ 13 $ 67 $ 233

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2021
Regulated Operations [Abstract]
Schedule of Delivery Rate Increases	The below table provides a summary of the approved delivery rate increases and delivery rate percentages, including rate levelization and excluding energy efficiency, which is a pass-through, for all four businesses. Rate years 2 and 3 commence on May 1, 2021 and 2022, respectively. Year 1 Year 2 Year 3 Rate Increase Delivery Rate % Rate Increase Delivery Rate % Rate Increase Delivery Rate % Utility (Millions) Increase (Millions) Increase (Millions) Increase 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 %
Schedule of Current and Non-Current Regulatory Assets	Regulatory assets as of September 30, 2021 and December 31, 2020, respectively, consisted of: September 30, December 31, As of 2021 2020 (Millions) Pension and other post-retirement benefits $ 814 $ 927 Pension and other post-retirement benefits cost deferrals 100 105 Storm costs 453 451 Rate adjustment mechanism 41 33 Revenue decoupling mechanism 53 58 Transmission revenue reconciliation mechanism 38 31 Contracts for differences 77 86 Hardship programs 22 20 Plant decommissioning 2 3 Deferred purchased gas 22 30 Deferred transmission expense 11 26 Environmental remediation costs 263 247 Debt premium 77 83 Unamortized losses on reacquired debt 23 26 Unfunded future income taxes 401 373 Federal tax depreciation normalization adjustment 144 148 Asset retirement obligation 21 21 Deferred meter replacement costs 42 33 COVID-19 cost recovery 20 1 Other 216 180 Total regulatory assets 2,840 2,882 Less: current portion 340 310 Total non-current regulatory assets $ 2,500 $ 2,572
Schedule of Current and Non-Current Regulatory Liabilities	Regulatory liabilities as of September 30, 2021 and December 31, 2020, respectively, consisted of: September 30, December 31, As of 2021 2020 (Millions) Energy efficiency portfolio standard $ 46 $ 58 Gas supply charge and deferred natural gas cost 3 3 Pension and other post-retirement benefits cost deferrals 49 59 Carrying costs on deferred income tax bonus depreciation 27 34 Carrying costs on deferred income tax - Mixed Services 263A 8 11 2017 Tax Act 1,366 1,435 Rate Change Levelization 98 55 Revenue decoupling mechanism 20 9 Accrued removal obligations 1,195 1,184 Asset sale gain account 3 7 Economic development 28 28 Positive benefit adjustment 24 30 Theoretical reserve flow thru impact 7 10 Deferred property tax 24 31 Net plant reconciliation 17 20 Debt rate reconciliation 53 63 Rate refund – FERC ROE proceeding 35 33 Transmission congestion contracts 22 22 Merger-related rate credits 12 14 Accumulated deferred investment tax credits 24 25 Asset retirement obligation 18 18 Earning sharing provisions 14 17 Middletown/Norwalk local transmission network service collections 17 18 Low income programs 29 28 Non-firm margin sharing credits 20 14 New York 2018 winter storm settlement 6 9 Hedge gains 88 — Other 168 176 Total regulatory liabilities 3,421 3,411 Less: current portion 367 274 Total non-current regulatory liabilities $ 3,054 $ 3,137

Fair Value of Financial Instr_2

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2021
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of September 30, 2021 and December 31, 2020, respectively, consisted of: As of September 30, 2021 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 39 $ 16 $ — $ — $ 55 Derivative assets Derivative financial instruments - power $ 69 $ 37 $ 118 $ (73) $ 151 Derivative financial instruments - gas 24 64 15 (73) 30 Contracts for differences — — 2 — 2 Derivative financial instruments – Other — 4 1 — 5 Total $ 93 $ 105 $ 136 $ (146) $ 188 Derivative liabilities Derivative financial instruments - power $ (5) $ (186) $ (116) $ 202 $ (105) Derivative financial instruments - gas — (39) (3) 38 (4) Contracts for differences — — (79) — (79) Derivative financial instruments – Other — (69) — — (69) Total $ (5) $ (294) $ (198) $ 240 $ (257) As of December 31, 2020 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 49 $ 14 $ — $ — $ 63 Derivative assets Derivative financial instruments - power $ 5 $ 31 $ 105 $ (54) $ 87 Derivative financial instruments - gas — 24 19 (35) 8 Contracts for differences — — 2 — 2 Total $ 5 $ 55 $ 126 $ (89) $ 97 Derivative liabilities Derivative financial instruments - power $ (23) $ (31) $ (23) $ 72 $ (5) Derivative financial instruments - gas (1) (9) (2) 9 (3) Contracts for differences — — (88) — (88) Total $ (24) $ (40) $ (113) $ 81 $ (96)
Fair Value, Financial Instrument Based on Level 3 Reconciliation	The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and nine months ended September 30, 2021 and 2020, respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2021 2020 2021 2020 Fair Value Beginning of Period, $ (20) $ 16 $ 13 $ 25 Gains recognized in operating revenues 5 2 40 10 (Losses) recognized in operating revenues (14) — (33) (4) Total gains recognized in operating revenues (9) 2 7 6 Gains recognized in OCI — — 1 2 (Losses) recognized in OCI (18) (1) (65) (7) Total (losses) recognized in OCI (18) (1) (64) (5) Net change recognized in regulatory assets and liabilities 4 3 9 2 Purchases (14) (1) (18) — Settlements (4) (1) (8) (9) Transfers out of Level 3 (a) (1) (1) (1) (2) Fair Value as of September 30, $ (62) $ 17 $ (62) $ 17 Gains for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ (9) $ 2 $ 7 $ 6 (a) Transfers out of Level 3 were the result of increased observability of market data. Range at Unobservable Input September 30, 2021 Risk of non-performance 0.39% - 0.53% Discount rate 0.53% - 0.98% Forward pricing ($ per KW-month) $2.00 - $4.80
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques	The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives. For the Nine Months Ended September 30, 2021 Index Avg. Max. Min. NYMEX ($/MMBtu) $ 2.98 $ 6.06 $ 2.27 AECO ($/MMBtu) $ 2.27 $ 7.40 $ (0.15) Ameren ($/MWh) $ 29.69 $ 81.39 $ 18.01 COB ($/MWh) $ 44.30 $ 231.90 $ 9.15 ComEd ($/MWh) $ 27.36 $ 75.88 $ 14.98 ERCOT N hub ($/MWh) $ 33.09 $ 140.00 $ 13.66 ERCOT S hub ($/MWh) $ 32.46 $ 140.00 $ 13.88 Indiana hub ($/MWh) $ 31.70 $ 83.18 $ 20.74 Mid C ($/MWh) $ 40.78 $ 229.90 $ 5.15 Minn hub ($/MWh) $ 26.34 $ 80.38 $ 15.23 NoIL hub ($/MWh) $ 27.12 $ 75.76 $ 14.64 PJM W hub ($/MWh) $ 30.61 $ 96.94 $ 17.78

Derivative Instruments and He_2

Derivative Instruments and Hedging (Tables)	9 Months Ended
	Sep. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Condensed Consolidated Balance Sheet and Amounts	The tables below present Networks' derivative positions as of September 30, 2021 and December 31, 2020, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets: As of September 30, 2021 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 86 $ 8 $ 1 $ 4 Derivative liabilities (1) (4) (14) (68) 85 4 (13) (64) Designated as hedging instruments Derivative assets 1 — — — Derivative liabilities — — (3) — 1 — (3) — Total derivatives before offset of cash collateral 86 4 (16) (64) Cash collateral receivable — — — — Total derivatives as presented in the balance sheet $ 86 $ 4 $ (16) $ (64) 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) The tables below present Renewables' derivative positions as of September 30, 2021 and December 31, 2020, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets: As of September 30, 2021 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 48 $ 80 $ 82 $ 17 Derivative liabilities (15) (10) (121) (21) 33 70 (39) (4) Designated as hedging instruments Derivative assets — — 2 5 Derivative liabilities (8) — (91) (128) (8) — (89) (123) Total derivatives before offset of cash collateral 25 70 (128) (127) Cash collateral (payable) receivable (1) — 50 45 Total derivatives as presented in the balance sheet $ 24 $ 70 $ (78) $ (82) 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)
Schedule of Notional Volumes of Outstanding Derivative Positions	The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of September 30, 2021 and December 31, 2020, respectively, consisted of: September 30, December 31, As of 2021 2020 (Millions) Wholesale electricity purchase contracts (MWh) 5.6 5.6 Natural gas purchase contracts (Dth) 9.4 9.5 Fleet fuel purchase contracts (Gallons) 2.7 2.5 The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of September 30, 2021 and December 31, 2020, respectively, consisted of: September 30, December 31, As of 2021 2020 (MWh/Dth in millions) Wholesale electricity purchase contracts 4 3 Wholesale electricity sales contracts 10 7 Natural gas and other fuel purchase contracts 22 24 Financial power contracts 10 12 Basis swaps – purchases 36 35 Basis swaps – sales 2 2
Schedule of Unrealized Gains and Losses from Fair Value Adjustments	The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of September 30, 2021 and December 31, 2020 and amounts reclassified from regulatory assets and liabilities into income for the three and nine months ended September 30, 2021 and 2020 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of Three Months Ended September 30, Nine Months Ended September 30, September 30, 2021 Electricity Natural Gas 2021 Electricity Natural Gas Electricity Natural Gas Regulatory assets $ — $ — Purchased power, natural gas and fuel used $ (18) $ — $ (8) $ (1) Regulatory liabilities $ (64) $ (24) December 31, 2020 2020 Regulatory assets $ 17 $ 1 Purchased power, natural gas and fuel used $ 8 $ — $ 41 $ 5 The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three and nine months ended September 30, 2021 and 2020, respectively, were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Millions) Derivative assets $ — $ — $ — $ — Derivative liabilities $ 4 $ 3 $ 9 $ 2
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ — Interest expense $ 1 $ 70 Foreign currency exchange contracts (1) — Total $ (1) $ 1 2020 Interest rate contracts $ — Interest expense $ 1 $ 86 Commodity contracts (1) Purchased power, natural gas and fuel used — 259 Total $ (1) $ 1 Nine Months Ended September 30, Gain (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) 2021 Interest rate contracts $ — Interest expense $ 3 $ 218 Commodity contracts 1 Purchased power, natural gas and fuel used — 1,085 Foreign currency exchange contracts (4) — Total $ (3) $ 3 2020 Interest rate contracts $ — Interest expense $ 3 $ 251 Commodity contracts (2) Purchased power, natural gas and fuel used 1 999 Foreign currency exchange contracts (2) — Total $ (4) $ 4 (a) Changes in accumulated OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Loss Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ (18) Interest expense $ — $ 70 Commodity contracts (78) Operating revenues 1 $ 1,598 Total $ (96) $ 1 2020 Commodity contracts $ (17) Operating revenues $ 5 $ 1,470 Nine Months Ended September 30, Loss Recognized in OCI on Derivatives (a) Location of Gain Reclassified from Accumulated OCI into Income (Gain) Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ (50) Interest expense $ — $ 218 Commodity contracts (170) Operating revenues (5) $ 5,041 Total $ (220) $ (5) 2020 Commodity contracts $ (9) Operating revenues $ 4 $ 4,651 (a) Changes in OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ — Interest expense $ 2 $ 70 2020 Interest rate contracts $ — Interest expense $ 2 $ 86 Nine Months Ended September 30, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ — Interest expense $ 7 $ 218 2020 Interest rate contracts $ (27) Interest expense $ 5 $ 251 (a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods which end in 2025 and 2029.
Schedule of Fair Values of Derivative Contracts	The fair values of derivative contracts associated with Renewables' activities as of September 30, 2021 and December 31, 2020, respectively, consisted of: September 30, December 31, As of 2021 2020 (Millions) Wholesale electricity purchase contracts $ 68 $ 4 Wholesale electricity sales contracts (131) 11 Natural gas and other fuel purchase contracts 2 — Financial power contracts 45 66 Basis swaps – purchases — 7 Total $ (16) $ 88 On May 27, 2021, Renewables entered into a forward interest rate swap, with a total notional amount of $935 million, to hedge the issuance of forecasted variable rate debt. The forward interest rate swap is designated and qualifies as a cash flow hedge. As part of the financial close of Vineyard Wind 1 described in Note 19, this hedge was novated to the lending institutions and the notional value changed to $956 million. As of September 30, 2021, the fair value of the interest rate swap was a $50 million non-current liability. The gain or loss on the interest rate swap is reported as a component of accumulated OCI and will be reclassified into earnings in the period or periods during which the related interest expense on the debt is incurred.
Schedule of Effects of Trading and Non-trading Derivatives	The effects of trading and non-trading derivatives associated with Renewables' activities for the three and nine months ended September 30, 2021, consisted of: Three Months Ended September 30, 2021 Nine Months Ended September 30, 2021 Trading Non-trading Total amount per income statement Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (6) $ 3 $ 8 $ 2 Wholesale electricity sales contracts (8) (16) (8) (53) Financial power contracts 14 (6) 5 (62) Financial and natural gas contracts (2) (22) (2) (39) Total (loss) gain included in operating revenues $ (2) $ (41) $ 1,598 $ 3 $ (152) $ 5,041 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 18 $ — $ 55 Financial power contracts — (5) — 1 Financial and natural gas contracts — 21 — 44 Total gain included in purchased power, natural gas and fuel used $ — $ 34 $ 319 $ — $ 100 $ 1,085 Total (Loss) Gain $ (2) $ (7) $ 3 $ (52) The effects of trading and non-trading derivatives associated with Renewables' activities for the three and nine months ended September 30, 2020, consisted of: Three Months Ended September 30, 2020 Nine Months Ended September 30, 2020 Trading Non-trading Total amount per income statement Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 3 $ — $ 1 $ — Wholesale electricity sales contracts (7) (11) (1) 4 Financial power contracts 4 (12) 1 2 Financial and natural gas contracts — (8) — (13) Total (loss) gain included in operating revenues $ — $ (31) $ 1,470 $ 1 $ (7) $ 4,651 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 9 $ — $ (2) Financial power contracts — 1 — — Financial and natural gas contracts — 16 — 19 Total gain included in purchased power, natural gas and fuel used $ — $ 26 $ 259 $ — $ 17 $ 999 Total (Loss) Gain $ — $ (5) $ 1 $ 10
Schedule of Fair Value Hedging Instruments	The effects on our condensed consolidated financial statements as of and for the three and nine months ended September 30, 2021 are as follows: (millions) Fair value of hedge Location of (Gain) Recognized in Income (Gain) Recognized in Income Year to date total per Income Statement As of September 30 ,2021 Three Months Ended September 30, 2021 Nine Months Ended September 30, 2021 Current Assets $ 4 Interest expense $ (1) $ (1) $ 218 Non-current liabilities $ (17) Cumulative effect on hedged debt Current debt $ (4) Non-current debt $ 17

Post-retirement and Similar O_2

Post-retirement and Similar Obligations (Tables)	9 Months Ended
	Sep. 30, 2021
Retirement Benefits [Abstract]
Components of Net Periodic Pension and Post-retirement Benefits	The components of net periodic benefit cost for pension benefits for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Millions) Service cost $ 10 $ 12 $ 30 $ 35 Interest cost 22 27 66 81 Expected return on plan assets (50) (50) (151) (150) Amortization of: Prior service costs — — 1 — Actuarial loss 29 31 88 94 Net Periodic Benefit Cost $ 11 $ 20 $ 34 $ 60 The components of net periodic benefit cost for postretirement benefits for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Millions) Service cost $ 1 $ 1 $ 2 $ 2 Interest cost 2 4 7 10 Expected return on plan assets (2) (2) (5) (6) Amortization of: Prior service costs (1) (3) (4) (7) Actuarial loss — — 1 1 Net Periodic Benefit Cost $ — $ — $ 1 $ —

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2021
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: As of June 30, Three Months Ended September 30, As of September 30, As of June 30, Three Months Ended September 30, As of September 30, 2021 2021 2021 2020 2020 2020 (Millions) Change in revaluation of defined benefit plans $ (12) $ — $ (12) $ (12) $ — $ (12) Loss on nonqualified pension plans (20) — (20) (7) — (7) Unrealized loss from equity method investment, net of income tax expense of $1 for 2021 (a) (3) (6) (9) — — — Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(23) for 2021 and $(3) for 2020 (135) (73) (208) (29) (15) (44) Reclassification to net income of losses on cash flow hedges, net of income tax (benefit) expense of $(2) for 2021 and $0 for 2020 (b) (39) 5 (34) (60) 9 (51) (Loss) Gain on derivatives qualifying as cash flow hedges (174) (68) (242) (89) (6) (95) Accumulated Other Comprehensive Loss $ (209) $ (74) $ (283) $ (108) $ (6) $ (114) As of December 31, Nine Months Ended September 30, As of September 30, As of December 31, Nine Months Ended September 30, As of September 30, 2020 2021 2021 2019 2020 2020 (Millions) Change in revaluation of defined benefit plans $ (12) $ — $ (12) $ (12) $ — $ (12) Loss on nonqualified pension plans (20) — (20) (7) — (7) Unrealized loss from equity method investment, net of income tax benefit of $(3) for 2021 (a) $ — $ (9) $ (9) $ — $ — $ — Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(49) for 2021 and $(8) for 2020 (35) (173) (208) (13) (31) (44) Reclassification to net income of losses on cash flow hedges, net of income tax (benefit) expense of $(6) for 2021 and $1 for 2020 (b) (44) 10 (34) (63) 12 (51) (Loss) Gain on derivatives qualifying as cash flow hedges (79) (163) (242) (76) (19) (95) Accumulated Other Comprehensive Loss $ (111) $ (172) $ (283) $ (95) $ (19) $ (114) (a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization and line items in our condensed consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2021
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 111 $ 87 $ 543 $ 415 Denominator: Weighted average number of shares outstanding - basic 387,321,484 309,491,082 348,264,388 309,496,234 Weighted average number of shares outstanding - diluted 387,676,085 309,550,126 348,714,535 309,554,838 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.29 $ 0.28 $ 1.56 $ 1.34 Earnings Per Common Share, Diluted $ 0.29 $ 0.28 $ 1.56 $ 1.34

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2021
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the three and nine months ended September 30, 2021, consisted of: Three Months Ended September 30, 2021 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,357 $ 243 $ (2) $ 1,598 Revenue - intersegment — — — — Depreciation and amortization 156 103 — 259 Operating income (loss) 158 (18) (2) 138 Earnings (losses) from equity method investments 3 (4) — (1) Interest expense, net of capitalization 51 — 19 70 Income tax expense (benefit) 8 (26) (6) (24) Adjusted net income $ 130 $ 18 $ (15) $ 133 Nine Months Ended September 30, 2021 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 4,148 $ 894 $ (1) $ 5,041 Revenue - intersegment 1 — (1) — Depreciation and amortization 461 294 1 756 Operating income 618 58 (1) 675 Earnings (losses) from equity method investments 10 (6) — 4 Interest expense, net of capitalization 157 — 61 218 Income tax expense (benefit) 74 (56) (18) — Adjusted net income 467 182 (39) 609 Capital expenditures 1,512 385 — 1,897 As of September 30, 2021 Property, plant and equipment 18,206 9,943 9 28,158 Equity method investments 141 430 — 571 Total assets $ 25,930 $ 12,272 $ 677 $ 38,879 (a) Includes Corporate and intersegment eliminations. Segment information for the three and nine months ended September 30, 2020 and as of December 31, 2020, consisted of: Three Months Ended September 30, 2020 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,194 $ 275 $ 1 $ 1,470 Revenue - intersegment 3 1 (4) — Depreciation and amortization 151 104 — 255 Operating income 160 7 (2) 165 Earnings (losses) from equity method investments 3 (2) — 1 Interest expense, net of capitalization 63 (1) 24 86 Income tax expense (benefit) 20 (7) 2 15 Adjusted net income $ 99 $ 32 $ (31) $ 100 Nine Months Ended September 30, 2020 Networks Renewables Other (a) AVANGRID (Millions) Revenue - external $ 3,775 $ 875 $ 1 $ 4,651 Revenue - intersegment 4 1 (5) — Depreciation and amortization 446 301 1 748 Operating income 617 24 6 647 Earnings (losses) from equity method investments 8 (11) — (3) Interest expense, net of capitalization 199 (1) 53 251 Income tax expense (benefit) 75 (53) (1) 21 Adjusted net income 379 108 (53) 434 Capital expenditures 1,312 648 — 1,960 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.
Schedule of Reconciliation of Adjusted Net Income to Net Income	Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three and nine months ended September 30, 2021 and 2020, respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 133 $ 100 $ 609 $ 434 Adjustments: Mark-to-market earnings - Renewables (1) (9) (7) (50) 9 Restructuring charges (2) — (1) — (5) Accelerated depreciation from repowering (3) — (3) — (9) Impact of COVID-19 (4) (19) (8) (33) (21) Merger costs (5) (3) — (6) — Income tax impact of adjustments 8 5 24 7 Net Income Attributable to Avangrid, Inc. $ 111 $ 87 $ 543 $ 415 (1) Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas. (2) Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth. (3) Represents the amount of accelerated depreciation derived from repowering of wind farms in Renewables. (4) Represents costs incurred in connection with the COVID-19 pandemic. (5) Pre-merger costs incurred.

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2021
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Related party transactions for the three and nine months ended September 30, 2021 and 2020, respectively, consisted of: Three Months Ended September 30, 2021 2020 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Renovables Energía, S.L. $ — $ (3) $ — $ (2) Iberdrola Financiación, S.A. $ — $ (4) $ — $ (3) Iberdrola $ — $ (14) $ — $ (10) Vineyard Wind $ 4 $ — $ 3 $ — Iberdrola Solutions $ (1) $ — $ 2 $ — Other $ — $ (1) $ — $ (1) Nine Months Ended September 30, 2021 2020 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Renovables Energía, S.L. $ — $ (8) $ — $ (6) Iberdrola Financiación, S.A. $ — $ (7) $ — $ (5) Iberdrola $ — $ (41) $ — $ (31) Vineyard Wind $ 12 $ — $ 7 $ — Iberdrola Solutions $ 7 $ (39) $ 2 $ — Other $ 1 $ (2) $ — $ (2) Related party balances as of September 30, 2021 and December 31, 2020, respectively, consisted of: As of September 30, 2021 December 31, 2020 (Millions) Owed By Owed To Owed By Owed To Iberdrola $ 2 $ (34) $ 2 $ (43) Iberdrola Renovables Energía, S.L. $ — $ (8) $ — $ — Iberdrola Financiación, S.A. $ — $ (7) $ — $ (6) Vineyard Wind $ 5 $ — $ 4 $ — Iberdrola Solutions $ — $ (3) $ 5 $ — Other $ — $ — $ 1 $ (1)

Other Financial Statement Ite_2

Other Financial Statement Items (Tables)	9 Months Ended
	Sep. 30, 2021
Balance Sheet Related Disclosures [Abstract]
Schedule of Accounts, Notes, Loans and Financing Receivable	Accounts receivable and unbilled revenues, net as of September 30, 2021 and December 31, 2020 consisted of: As of September 30, 2021 December 31, 2020 (Millions) Trade receivables and unbilled revenues $ 1,279 $ 1,295 Allowance for credit losses (174) (108) Accounts receivable and unbilled revenues, net $ 1,105 $ 1,187
Schedule of Allowance for Credit Loss	The change in the allowance for credit losses for the three and nine months ended September 30, 2021 and 2020 consisted of: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2021 2020 2021 2020 As of Beginning of Period, $ 150 $ 85 $ 108 $ 69 Current period provision 41 19 106 60 Write-off as uncollectible (17) (10) (40) (35) As of September 30, $ 174 $ 94 $ 174 $ 94
Schedule of Accumulated Depreciation and Amortization	The accumulated depreciation and amortization as of September 30, 2021 and December 31, 2020, respectively, were as follows: September 30, December 31, As of 2021 2020 (Millions) Property, plant and equipment Accumulated depreciation $ 10,421 $ 9,799 Intangible assets Accumulated amortization $ 329 $ 319

Background and Nature Of Oper_2

Background and Nature Of Operations (Details)	May 18, 2021USD ($)placement$ / sharesshares	Apr. 15, 2021	Oct. 20, 2020USD ($)$ / shares	Sep. 30, 2021$ / shares	Jun. 30, 2021$ / shares	Dec. 31, 2020$ / shares	Sep. 30, 2020$ / shares	Jun. 30, 2020$ / shares	Dec. 31, 2019$ / shares
Nature Of Business [Line Items]
Sale of stock, number of shares issued (in shares) | shares	77,821,012
Sale of stock, number of placements | placement	2
Common stock, par value (in dollars per share) | $ / shares	$ 0.01			$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Sale of stock, price (in dollars per share) | $ / shares	$ 51.40
Proceeds of private placements	$ 4,000,000,000
Proceeds of private placements, used to repay debt	$ 3,000,000,000
Iberdrola
Nature Of Business [Line Items]
Sale of stock, number of shares issued (in shares) | shares	63,424,125
Hyde Member LLC And Subsidiary Of Qatar Investment Authority
Nature Of Business [Line Items]
Sale of stock, number of shares issued (in shares) | shares	14,396,887
NM Green Holdings, Inc.
Nature Of Business [Line Items]
Merger agreement, share price (in dollars per share) | $ / shares			$ 50.30
Merger agreement term, ownership percentage benchmark (no more than)			15.00%
Merger agreement, termination rights term, extension period			3 months
Merger agreement, termination rights term, termination fees			$ 130,000,000
Merger agreement, termination rights term, termination fees as remedy			184,000,000
Merger agreement, termination rights term, termination fees, out-of-pocket fees and expenses reimbursable limit (up to)			$ 10,000,000
NM Green Holdings, Inc. | Side Letter Agreement Associated With Merger
Nature Of Business [Line Items]
Debt basis spread on variable rate		0.75%
Facility fee percentage on undrawn portion of funding commitment		0.12%
Avangrid | Iberdrola
Nature Of Business [Line Items]
Parent company, ownership percentage				81.50%
Avangrid | Various Shareholders
Nature Of Business [Line Items]
Ownership percentage by various shareholders				14.80%

Revenue - Narrative (Details)

Revenue - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Contract assets	$ 9		$ 9		$ 9
TCC contract liabilities	6		6		9
Revenue recognized	6	$ 6	15	$ 16
Accounts receivable related to contracts with customers	1,043		1,043		1,151
Unbilled revenues	266		266		$ 341
Revenue, remaining performance obligation, amount	$ 233		$ 233
Transmission congestion contracts | Min.
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing			6 months
Transmission congestion contracts | Max.
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing			2 years
Renewables
Disaggregation of Revenue [Line Items]
Capitalized contract cost amortization term			15 years

Revenue - Schedule of Revenues

Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 1,564	$ 1,405	$ 4,988	$ 4,402
Leasing revenue	1	2	6	5
Derivative revenue	22	25	(72)	111
Alternative revenue programs	8	24	77	109
Other revenue	3	14	42	24
Total operating revenues	1,598	1,470	5,041	4,651
Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,105	984	2,959	2,701
Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	214	166	1,034	910
Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	205	200	819	639
Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	10	6	21	16
Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	14	13	42	27
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	16	36	113	109
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(2)	(4)	(2)	(4)
Leasing revenue	0	0	0	0
Derivative revenue	0	0	0	0
Alternative revenue programs	0	0	0	0
Other revenue	0	1	0	0
Total operating revenues	(2)	(3)	(2)	(4)
Other | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Other | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Other | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Other | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Other | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Other | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(2)	(4)	(2)	(4)
Networks
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,336	1,162	4,034	3,649
Leasing revenue	1	2	6	5
Derivative revenue	0	0	0	0
Alternative revenue programs	8	24	77	109
Other revenue	12	9	32	16
Total operating revenues	1,357	1,197	4,149	3,779
Networks | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,105	984	2,959	2,701
Networks | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	214	166	1,034	910
Networks | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Networks | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Networks | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Networks | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	17	12	41	38
Renewables
Segment Reporting Information [Line Items]
Revenue from contracts with customers	230	247	956	757
Leasing revenue	0	0	0	0
Derivative revenue	22	25	(72)	111
Alternative revenue programs	0	0	0	0
Other revenue	(9)	4	10	8
Total operating revenues	243	276	894	876
Renewables | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Renewables | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Renewables | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	205	200	819	639
Renewables | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	10	6	21	16
Renewables | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	14	13	42	27
Renewables | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 1	$ 28	$ 74	$ 75

Revenue - Schedule of Aggregate

Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details) $ in Millions	Sep. 30, 2021USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 233
Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	8
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	145
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	80
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 25
Remaining performance obligation, period	3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 71
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 6
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 26
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	$ 39
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	$ 42
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	$ 18
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	$ 23
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	$ 25
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 14
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 10
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 15
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 12
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 3
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 13
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 10
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 3
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 67
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 65
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 2
Remaining performance obligation, period

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities - Additional Information (Details)

Jul. 14, 2021USD ($)

Jun. 23, 2021USD ($)

May 06, 2021USD ($)

Nov. 19, 2020

Feb. 19, 2020USD ($)

Jan. 01, 2019

Jan. 01, 2018

Jan. 01, 2017

Sep. 30, 2021USD ($)

Sep. 30, 2020USD ($)

Sep. 30, 2021USD ($)

Sep. 30, 2020USD ($)

Dec. 31, 2019

Jun. 30, 2021USD ($)hour

Regulatory Assets And Liabilities [Line Items]

Unrecorded regulatory assets

$ 1,306,000,000

$ 1,306,000,000

Energy legislation settlement agreement, contribution amount

$ 5,000,000

Energy legislation settlement agreement, customers rate credits provided

50,000,000

Energy legislation settlement agreement, customers rate credits collected in rate adjustment mechanism

$ 52,000,000

Energy legislation settlement agreement, customers rate credits provided, period

22 months

Energy legislation, customer compensation and reimbursement provisions, power outage hours benchmark (more than) | hour

96

Energy legislation, customer compensation and reimbursement provisions, customer payment per day

$ 25

Energy legislation, customer compensation and reimbursement provisions, food and medicine reimbursement

$ 250

Civil penalty amount

$ 1,000,000

$ 2,000,000

Unfunded future income tax expense collection period

46 years

UIL Holdings

Regulatory Assets And Liabilities [Line Items]

Business combination merger related rate credits

$ 1,000,000

$ 2,000,000

$ 1,000,000

$ 2,000,000

Energy efficiency portfolio standard

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

Carrying costs on deferred income tax bonus depreciation

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

Carrying costs on deferred income tax - Mixed Services 263A

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

Rate Change Levelization

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

Positive benefit adjustment

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

Theoretical reserve flow thru impact | Min.

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

Theoretical reserve flow thru impact | Max.

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

Deferred property tax

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

Net plant reconciliation

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

Transmission congestion contracts

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

New York 2018 winter storm settlement

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

Central Maine Power

Regulatory Assets And Liabilities [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%

Service quality measures for a period

18 months

Deferred income tax recovery period

32 years 6 months

NYSEG and RG&E

Regulatory Assets And Liabilities [Line Items]

Return on equity

8.80%

Equity ratio for earnings sharing

48.00%

Equity ratio

50.00%

NYSEG and RG&E | Economic development

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

United Illuminating Company (UI) | PURA

Regulatory Assets And Liabilities [Line Items]

Return on equity

9.10%

Equity ratio

50.00%

New distribution rate schedule, period

3 years

Public utilities regulatory authority distribution rate

50.00%

SCG | PURA

Regulatory Assets And Liabilities [Line Items]

Return on equity

9.25%

Equity ratio

52.00%

Connecticut Natural Gas Corporation (CNG) | PURA

Regulatory Assets And Liabilities [Line Items]

Return on equity

9.30%

Equity ratio, year one

54.00%

Equity ratio, year two

54.50%

Equity ratio, year three

55.00%

BGC | Massachusetts Department of Public Utilities (DPU)

Regulatory Assets And Liabilities [Line Items]

Equity ratio

54.00%

Public utilities regulatory authority distribution rate

9.70%

NYSEG | Asset sale gain account

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

RG&E | Asset sale gain account

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

2 years

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities - Rate Increases and Delivery Rate Percentages (Details) $ in Millions	Jun. 22, 2020USD ($)
NYSEG Electric | Electric and Gas Service Rate Plan Year One
Regulatory Liabilities [Line Items]
Rate Increase	$ 34
Delivery rate increase	4.60%
NYSEG Electric | Electric and Gas Service Rate Plan Year Two
Regulatory Liabilities [Line Items]
Rate Increase	$ 46
Delivery rate increase	5.90%
NYSEG Electric | Electric and Gas Service Rate Plan Year Three
Regulatory Liabilities [Line Items]
Rate Increase	$ 36
Delivery rate increase	4.20%
NYSEG Gas | Electric and Gas Service Rate Plan Year One
Regulatory Liabilities [Line Items]
Rate Increase	$ 0
Delivery rate increase	0.00%
NYSEG Gas | Electric and Gas Service Rate Plan Year Two
Regulatory Liabilities [Line Items]
Rate Increase	$ 2
Delivery rate increase	0.80%
NYSEG Gas | Electric and Gas Service Rate Plan Year Three
Regulatory Liabilities [Line Items]
Rate Increase	$ 3
Delivery rate increase	1.60%
RG&E Electric | Electric and Gas Service Rate Plan Year One
Regulatory Liabilities [Line Items]
Rate Increase	$ 17
Delivery rate increase	3.80%
RG&E Electric | Electric and Gas Service Rate Plan Year Two
Regulatory Liabilities [Line Items]
Rate Increase	$ 14
Delivery rate increase	3.20%
RG&E Electric | Electric and Gas Service Rate Plan Year Three
Regulatory Liabilities [Line Items]
Rate Increase	$ 16
Delivery rate increase	3.30%
RG&E Gas | Electric and Gas Service Rate Plan Year One
Regulatory Liabilities [Line Items]
Rate Increase	$ 0
Delivery rate increase	0.00%
RG&E Gas | Electric and Gas Service Rate Plan Year Two
Regulatory Liabilities [Line Items]
Rate Increase	$ 0
Delivery rate increase	0.00%
RG&E Gas | Electric and Gas Service Rate Plan Year Three
Regulatory Liabilities [Line Items]
Rate Increase	$ 2
Delivery rate increase	1.30%

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Regulatory Assets [Line Items]
Total regulatory assets	$ 2,840	$ 2,882
Less: current portion	340	310
Total non-current regulatory assets	2,500	2,572
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Total regulatory assets	814	927
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Total regulatory assets	100	105
Storm costs
Regulatory Assets [Line Items]
Total regulatory assets	453	451
Rate adjustment mechanism
Regulatory Assets [Line Items]
Total regulatory assets	41	33
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Total regulatory assets	53	58
Transmission revenue reconciliation mechanism
Regulatory Assets [Line Items]
Total regulatory assets	38	31
Contracts for differences
Regulatory Assets [Line Items]
Total regulatory assets	77	86
Hardship programs
Regulatory Assets [Line Items]
Total regulatory assets	22	20
Plant decommissioning
Regulatory Assets [Line Items]
Total regulatory assets	2	3
Deferred purchased gas
Regulatory Assets [Line Items]
Total regulatory assets	22	30
Deferred transmission expense
Regulatory Assets [Line Items]
Total regulatory assets	11	26
Environmental remediation costs
Regulatory Assets [Line Items]
Total regulatory assets	263	247
Debt premium
Regulatory Assets [Line Items]
Total regulatory assets	77	83
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Total regulatory assets	23	26
Unfunded future income taxes
Regulatory Assets [Line Items]
Total regulatory assets	401	373
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Total regulatory assets	144	148
Asset retirement obligation
Regulatory Assets [Line Items]
Total regulatory assets	21	21
Deferred meter replacement costs
Regulatory Assets [Line Items]
Total regulatory assets	42	33
COVID-19 cost recovery
Regulatory Assets [Line Items]
Total regulatory assets	20	1
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 216	$ 180

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 3,421	$ 3,411
Less: current portion	367	274
Total non-current regulatory liabilities	3,054	3,137
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	46	58
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	3	3
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	49	59
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	27	34
Carrying costs on deferred income tax - Mixed Services 263A
Regulatory Liabilities [Line Items]
Total regulatory liabilities	8	11
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,366	1,435
Rate Change Levelization
Regulatory Liabilities [Line Items]
Total regulatory liabilities	98	55
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	20	9
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,195	1,184
Asset sale gain account
Regulatory Liabilities [Line Items]
Total regulatory liabilities	3	7
Economic development
Regulatory Liabilities [Line Items]
Total regulatory liabilities	28	28
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	24	30
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Total regulatory liabilities	7	10
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	24	31
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	20
Debt rate reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	53	63
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Total regulatory liabilities	35	33
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Total regulatory liabilities	22	22
Merger-related rate credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	12	14
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	24	25
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	18
Earning sharing provisions
Regulatory Liabilities [Line Items]
Total regulatory liabilities	14	17
Middletown/Norwalk local transmission network service collections
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	18
Low income programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities	29	28
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	20	14
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Total regulatory liabilities	6	9
Hedge gains
Regulatory Liabilities [Line Items]
Total regulatory liabilities	88	0
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 168	$ 176

Fair Value of Financial Instr_3

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative delivery period (in years)	2 years
Restricted cash	$ 347	$ 331
Fair value of debt	8,800	12,166
Restricted Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restricted cash	$ 4	$ 4
RG&E
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of electric load obligations using contracts for a NYISO location	70.00%

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	Sep. 30, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	$ 55	$ 63
Netting adjustment	(146)	(89)
Derivative assets	188	97
Netting adjustment	240	81
Derivative liabilities	(257)	(96)
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(73)	(54)
Derivative assets	151	87
Netting adjustment	202	72
Derivative liabilities	(105)	(5)
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(73)	(35)
Derivative assets	30	8
Netting adjustment	38	9
Derivative liabilities	(4)	(3)
Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0	0
Derivative assets	2	2
Netting adjustment	0	0
Derivative liabilities	(79)	(88)
Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0
Derivative assets	5
Netting adjustment	0
Derivative liabilities	(69)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	39	49
Derivative assets, before netting	93	5
Derivative liabilities, before netting	(5)	(24)
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	69	5
Derivative liabilities, before netting	(5)	(23)
Level 1 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	24	0
Derivative liabilities, before netting	0	(1)
Level 1 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	0	0
Level 1 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0
Derivative liabilities, before netting	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	16	14
Derivative assets, before netting	105	55
Derivative liabilities, before netting	(294)	(40)
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	37	31
Derivative liabilities, before netting	(186)	(31)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	64	24
Derivative liabilities, before netting	(39)	(9)
Level 2 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	0	0
Level 2 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	4
Derivative liabilities, before netting	(69)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	0	0
Derivative assets, before netting	136	126
Derivative liabilities, before netting	(198)	(113)
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	118	105
Derivative liabilities, before netting	(116)	(23)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	15	19
Derivative liabilities, before netting	(3)	(2)
Level 3 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	2	2
Derivative liabilities, before netting	(79)	$ (88)
Level 3 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	1
Derivative liabilities, before netting	$ 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	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value Beginning of Period,	$ (20)	$ 16	$ 13	$ 25
Gains recognized in operating revenues	5	2	40	10
(Losses) recognized in operating revenues	(14)	0	(33)	(4)
Total gains recognized in operating revenues	(9)	2	7	6
Gains recognized in OCI	0	0	1	2
(Losses) recognized in OCI	(18)	(1)	(65)	(7)
Total (losses) recognized in OCI	(18)	(1)	(64)	(5)
Net change recognized in regulatory assets and liabilities	4	3	9	2
Purchases	(14)	(1)	(18)	0
Settlements	(4)	(1)	(8)	(9)
Transfers out of Level 3 (a)	(1)	(1)	(1)	(2)
Fair Value as of September 30,	(62)	17	(62)	17
Gains for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$ (9)	$ 2	$ 7	$ 6

Fair Value of Financial Instr_6

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Details) - Measurement Input, Commodity Forward Price	Sep. 30, 2021$ / MWh$ / MMBTU
CME SWAPS MARKETS (NYMEX) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	2.98
CME SWAPS MARKETS (NYMEX) | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	6.06
CME SWAPS MARKETS (NYMEX) | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	2.27
AECO | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	2.27
AECO | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	7.40
AECO | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	(0.15)
Ameren | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	29.69
Ameren | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	81.39
Ameren | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	18.01
COB | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	44.30
COB | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	231.90
COB | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	9.15
ComEd | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	27.36
ComEd | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	75.88
ComEd | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	14.98
ERCOT N hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	33.09
ERCOT N hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	140
ERCOT N hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	13.66
ERCOT S hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	32.46
ERCOT S hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	140
ERCOT S hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	13.88
Indiana hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	31.70
Indiana hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	83.18
Indiana hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	20.74
Mid C | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	40.78
Mid C | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	229.90
Mid C | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	5.15
Minn hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	26.34
Minn hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	80.38
Minn hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	15.23
NoIL hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	27.12
NoIL hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	75.76
NoIL hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	14.64
PJM W hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	30.61
PJM W hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	96.94
PJM W hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	17.78

Fair Value of Financial Instr_7

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Details) - Level 3 - Contracts for differences	Sep. 30, 2021$ / kilowatt-MonthOfEnergy
Min. | Risk of non-performance
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0039
Min. | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0053
Min. | Forward pricing
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	2
Max. | Risk of non-performance
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0053
Max. | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0098
Max. | Forward pricing
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	4.80

Derivative Instruments and He_3

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	$ 188	$ 97
Derivative liabilities	(257)	(96)
Cash collateral (payable) receivable, assets	(55)	(18)
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, assets	86	0
Cash collateral (payable) receivable, assets	0	0
Total derivatives as presented in the balance sheet, assets	86	0
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	86	3
Derivative liabilities, gross	(1)	(3)
Derivative assets	85	0
Networks | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	1	0
Derivative liabilities, gross	0	0
Derivative assets	1	0
Networks | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, assets	4	1
Cash collateral (payable) receivable, assets	0	0
Total derivatives as presented in the balance sheet, assets	4	1
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	8	5
Derivative liabilities, gross	(4)	(4)
Derivative assets	4	1
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	0	0
Derivative liabilities, gross	0	0
Derivative assets	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liabilities	(16)	(32)
Cash collateral (payable) receivable, liabilities	0	18
Total derivatives as presented in the balance sheet, liabilities	(16)	(14)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	1	3
Derivative liabilities, gross	(14)	(34)
Derivative liabilities	(13)	(31)
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	0	0
Derivative liabilities, gross	(3)	(1)
Derivative liabilities	(3)	(1)
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liabilities	(64)	(75)
Cash collateral (payable) receivable, liabilities	0	1
Total derivatives as presented in the balance sheet, liabilities	(64)	(74)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	4	3
Derivative liabilities, gross	(68)	(78)
Derivative liabilities	(64)	(75)
Networks | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	0	0
Derivative liabilities, gross	0	0
Derivative liabilities	0	0
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, assets	25	27
Cash collateral (payable) receivable, assets	(1)	(9)
Total derivatives as presented in the balance sheet, assets	24	18
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	48	47
Derivative liabilities, gross	(15)	(23)
Derivative assets	33	24
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	0	8
Derivative liabilities, gross	(8)	(5)
Derivative assets	(8)	3
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, assets	70	96
Cash collateral (payable) receivable, assets	0	(18)
Total derivatives as presented in the balance sheet, assets	70	78
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	80	89
Derivative liabilities, gross	(10)	(2)
Derivative assets	70	87
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	0	15
Derivative liabilities, gross	0	(6)
Derivative assets	0	9
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liabilities	(128)	(3)
Cash collateral (payable) receivable, liabilities	50	0
Total derivatives as presented in the balance sheet, liabilities	(78)	(3)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	82	2
Derivative liabilities, gross	(121)	(4)
Derivative liabilities	(39)	(2)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	2	2
Derivative liabilities, gross	(91)	(3)
Derivative liabilities	(89)	(1)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liabilities	(127)	(5)
Cash collateral (payable) receivable, liabilities	45	0
Total derivatives as presented in the balance sheet, liabilities	(82)	(5)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	17	9
Derivative liabilities, gross	(21)	(11)
Derivative liabilities	(4)	(2)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets, gross	5	7
Derivative liabilities, gross	(128)	(10)
Derivative liabilities	$ (123)	$ (3)

Derivative Instruments and He_4

Derivative Instruments and Hedging - Net Notional Volume (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2021USD ($)MMBTUMWhgal	Dec. 31, 2020USD ($)MWhMMBTUgal
Networks | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	5.6	5.6
Networks | Natural Gas Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	9.4	9.5
Networks | Fleet Fuel Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount | gal	2.7	2.5
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (16)	$ 88
Renewables | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	4	3
Derivative assets (liabilities), fair value	$ 68	$ 4
Renewables | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	10	7
Derivative assets (liabilities), fair value	$ (131)	$ 11
Renewables | Natural Gas and Other fuel Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	22	24
Derivative assets (liabilities), fair value	$ 2	$ 0
Renewables | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	10	12
Derivative assets (liabilities), fair value	$ 45	$ 66
Renewables | Basis swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 0	$ 7
Renewables | Basis swaps | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	36	35
Renewables | Basis swaps | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	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	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Derivative assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ 0	$ 0	$ 0	$ 0
Derivative liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	(4)	(3)	(9)	(2)
Electricity | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0		0		$ 17
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	(18)	8	(8)	41
Electricity | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	(64)		(64)
Natural Gas | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0		0		$ 1
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	0	$ 0	(1)	$ 5
Natural Gas | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	$ (24)		$ (24)

Derivative Instruments and He_6

Derivative Instruments and Hedging - Additional Information (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021USD ($)instrument	Sep. 30, 2020USD ($)	Sep. 30, 2021USD ($)instrument	Sep. 30, 2020USD ($)	Sep. 15, 2021USD ($)	Jul. 15, 2021USD ($)	May 27, 2021USD ($)	Dec. 31, 2020USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory assets	$ 2,840		$ 2,840					$ 2,882
Regulatory liabilities	3,421		3,421					3,411
Gain (loss) recognized in OCI on derivatives	(96)		(220)
Derivative liability, noncurrent	163		163					79
Derivative liability	257		257					96
Aggregate fair value of additional collateral	14		14
Cash collateral pledged	55		55					18
Collateral already posted	$ 52		$ 52
Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative instruments | instrument	2		2
Derivative liability	$ 79		$ 79					88
Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(2)	$ (2)	(7)	$ (5)
Interest Rate Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	0	0	(27)
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	50		50					57
Cash Flow Hedging | Interest Rate Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Expected amortization of net gain (loss) on interest rate contracts	(2)		(2)
Fair Value Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative liability						$ 750
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(1)	(1)	(3)	(4)
Networks | Interest Rate Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	0	0	0
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(1)	$ (1)	(3)	$ (3)
Expected amortization of discontinued cash flow hedges in 2021	1		1
Unrealized losses on hedge derivatives reported in OCI			(3)
Unrealized gains (losses) on hedge derivatives to be reclassified within next 12 months			0
Networks | Cash Flow Hedging | Previously Settled Forward Starting Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	48		$ 48					51
Networks | Cash Flow Hedging | Fuel Derivatives
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum period of time of cash flow hedges			12 months
Renewables | Interest Rate Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(18)		$ (50)
Renewables | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gains (losses) on hedge derivatives to be reclassified within next 12 months			(94)
Renewables | Cash Flow Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount					$ 956		$ 935
Derivative liability, noncurrent	50		$ 50
UI | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers			20.00%
Gross derivative asset	2		$ 2					2
Regulatory assets	77		77					86
Gross amounts of recognized liabilities	79		79					88
Regulatory liabilities	0		$ 0					0
CL&P | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers			80.00%
Gross derivative asset	0		$ 0					0
Gross amounts of recognized liabilities	$ 76		$ 76					$ 85

Derivative Instruments and He_7

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain recognized in OCI on derivatives	$ (96)		$ (220)
Loss Reclassified from Accumulated OCI into Income	1		(5)
Interest expense	70	$ 86	218	$ 251
Purchased power, natural gas and fuel used	319	259	1,085	999
Revenues	1,598	1,470	5,041	4,651
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain recognized in OCI on derivatives	(1)	(1)	(3)	(4)
Loss Reclassified from Accumulated OCI into Income	1	1	3	4
Revenues	1,357	1,197	4,149	3,779
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Revenues	243	276	894	876
Interest Rate Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain recognized in OCI on derivatives	0	0	0	(27)
Interest Rate Contract | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	2	2	7	5
Interest Rate Contract | Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain recognized in OCI on derivatives	0	0	0	0
Interest Rate Contract | Networks | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	1	1	3	3
Interest Rate Contract | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain recognized in OCI on derivatives	(18)		(50)
Revenues	70		218
Interest Rate Contract | Renewables | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	0		0
Commodity Contract | Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain recognized in OCI on derivatives		(1)	1	(2)
Commodity Contract | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income		0	0	1
Commodity Contract | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain recognized in OCI on derivatives	(78)	(17)	(170)	(9)
Revenues	1,598		5,041
Commodity Contract | Renewables | Operating revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	1	$ 5	(5)	4
Foreign Exchange Contract | Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain recognized in OCI on derivatives	$ (1)		$ (4)	$ (2)

Derivative Instruments and He_8

Derivative Instruments and Hedging - Fair Values of Derivative Contracts (Details) - Renewables - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (16)	$ 88
Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	45	66
Basis swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	0	7
Long | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	68	4
Long | Natural Gas and Other fuel Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	2	0
Short | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (131)	$ 11

Derivative Instruments and He_9

Derivative Instruments and Hedging - Effect of Trading and Non-trading Derivatives (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Revenues	$ 1,598	$ 1,470	$ 5,041	$ 4,651
Utilities operating expense, purchased power	319	259	1,085	999
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Revenues	243	276	894	876
Renewables | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(2)	0	3	1
Renewables | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(7)	(5)	(52)	10
Renewables | Operating revenues | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(2)	0	3	1
Renewables | Operating revenues | Trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(6)	3	8	1
Renewables | Operating revenues | Trading | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(8)	(7)	(8)	(1)
Renewables | Operating revenues | Trading | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	14	4	5	1
Renewables | Operating revenues | Trading | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(2)	0	(2)	0
Renewables | Operating revenues | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(41)	(31)	(152)	(7)
Revenues			5,041	4,651
Renewables | Operating revenues | Non-trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	3	0	2	0
Renewables | Operating revenues | Non-trading | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(16)	(11)	(53)	4
Renewables | Operating revenues | Non-trading | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(6)	(12)	(62)	2
Renewables | Operating revenues | Non-trading | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(22)	(8)	(39)	(13)
Renewables | Purchased power, natural gas and fuel used | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0	0	0
Renewables | Purchased power, natural gas and fuel used | Trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0	0	0
Renewables | Purchased power, natural gas and fuel used | Trading | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0	0	0
Renewables | Purchased power, natural gas and fuel used | Trading | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0	0	0
Renewables | Purchased power, natural gas and fuel used | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	34	26	100	17
Utilities operating expense, purchased power			1,085	999
Renewables | Purchased power, natural gas and fuel used | Non-trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	18	9	55	(2)
Renewables | Purchased power, natural gas and fuel used | Non-trading | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(5)	1	1	0
Renewables | Purchased power, natural gas and fuel used | Non-trading | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 21	$ 16	$ 44	$ 19

Derivative Instruments and H_10

Derivative Instruments and Hedging - Schedule of Fair Value Hedge (Details) - Interest Rate Swap $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2021USD ($)	Sep. 30, 2021USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged asset, fair value hedge	$ 4	$ 4
Hedged liability, fair value hedge	(17)	(17)
(Gain) Recognized in Income	(1)	(1)
Fair Value Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Year to date total per Income Statement		218
Current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	(4)	(4)
Non-current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	$ 17	$ 17

Contingencies and Commitments (

Contingencies and Commitments (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

Apr. 30, 2018

Sep. 30, 2021USD ($)

Dec. 31, 2001plaintiff

Aug. 12, 2021USD ($)

Jan. 04, 2021USD ($)

Dec. 31, 2020USD ($)

Apr. 12, 2016USD ($)

Loss Contingencies [Line Items]

Refund period term

15 months

Approved return on equity

9.88%

Regulatory liabilities

$ 3,054

$ 3,137

Number of claims | complaint

2

Requested existing base return on equity base percentage

10.02%

9.88%

Estimated reduction in earnings per year provided effective of supplemental notice of proposed rulemaking

3

Number of plaintiffs | plaintiff

2

Show cause order, period

30 days

Show cause order, number of alleged violations with civil action for injunctive relief | violation

11

Show Cause Order settlement payment

$ 3

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

474

Future payments committed

$ 90

Vineyard Wind

Loss Contingencies [Line Items]

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

25

Max.

Loss Contingencies [Line Items]

Show Cause Order settlement payment

$ 5

Complaint II

Loss Contingencies [Line Items]

Regulatory liabilities

27

Complaint III

Loss Contingencies [Line Items]

Regulatory liabilities

8

Complaint II and III

Loss Contingencies [Line Items]

Reasonably possible loss, in additional reserve, pre tax

$ 17

California Energy Crisis Litigation

Loss Contingencies [Line Items]

Price of the power purchase agreements

$ 259

Requested renewables delay from preliminary proposed ruling period

2 years

Unfavorable Regulatory Action | Complaint I

Loss Contingencies [Line Items]

Approved return on equity

10.57%

Number of claims | complaint

4

Unfavorable Regulatory Action | Complaint I | Max.

Loss Contingencies [Line Items]

Approved return on equity

11.74%

11.74%

Unfavorable Regulatory Action | Complaint II

Loss Contingencies [Line Items]

Approved return on equity

9.59%

Refund period

15 months

Unfavorable Regulatory Action | Complaint II | Max.

Loss Contingencies [Line Items]

Approved return on equity

10.42%

Unfavorable Regulatory Action | Complaint III

Loss Contingencies [Line Items]

Approved return on equity

10.90%

Refund period

15 months

Unfavorable Regulatory Action | Complaint III | Max.

Loss Contingencies [Line Items]

Approved return on equity

12.19%

Before Amendment

Loss Contingencies [Line Items]

Requested return on equity base percentage

11.14%

Environmental Liabilities (Deta

Environmental Liabilities (Details)	Apr. 24, 2020USD ($)	Sep. 30, 2021USD ($)site	Dec. 31, 2011site	Dec. 31, 2008site	Sep. 30, 2021USD ($)	Dec. 31, 2020USD ($)	Aug. 04, 2016USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		26
Number of sites with liability recorded		11
Number of sites note expected to incur additional liabilities		15
Number of additional sites with liability recorded		12
Number of sites where gas was manufactured in the past		53
Number of sites for which we have entered into consent orders to investigate and remediate		41
Accrual related to investigation and remediation | $		$ 310,000,000			$ 310,000,000	$ 300,000,000
Accrual related to investigation and remediation, amount recorded to date | $					35,000,000
Loss contingency, damages sought, value | $	$ 5,000,000
FirstEnergy
Environmental Exit Cost [Line Items]
Number of sites in dispute			16
United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		$ 22,000,000			22,000,000	22,000,000	$ 30,000,000
New York State Registry
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		16
Number of sites where gas was manufactured in the past		6
Maine's Uncontrolled Sites Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		5
Number of sites where gas was manufactured in the past		2
Brownfield Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		1
Massachusetts Non- Priority Confirmed Disposal Site List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		6
Ten of Twenty-five Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $		$ 7,000,000			7,000,000
Another Ten Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $		9,000,000			9,000,000
Another Ten Sites | Min.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $		15,000,000			15,000,000
Another Ten Sites | Max.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $		$ 22,000,000			22,000,000
New York Voluntary Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past		3
Maine's Voluntary Response Action Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past		3
Manufactured Gas Plants | Connecticut
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		$ 114,000,000			114,000,000	$ 96,000,000
Manufactured Gas Plants | Min.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		169,000,000			169,000,000
Manufactured Gas Plants | Max.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		282,000,000			282,000,000
Properties Where MGPs Had Historically Operated
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		0			0
MGP Sites | FirstEnergy
Environmental Exit Cost [Line Items]
Number of sites in dispute				2
NYSEG | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		16,000,000			16,000,000
RG&E | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		$ 7,000,000			$ 7,000,000

Post-retirement and Similar O_3

Post-retirement and Similar Obligations - Additional Information (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2021USD ($)	Sep. 30, 2021USD ($)
Retirement Benefits [Abstract]
Defined benefit, pension contributions	$ 13	$ 27
Additional contributions for remainder of fiscal year	$ 48	$ 48

Post-retirement and Similar O_4

Post-retirement and Similar Obligations - Periodic Benefit Costs Net (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 10	$ 12	$ 30	$ 35
Interest cost	22	27	66	81
Expected return on plan assets	(50)	(50)	(151)	(150)
Prior service costs	0	0	1	0
Actuarial loss	29	31	88	94
Net Periodic Benefit Cost	11	20	34	60
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	1	2	2
Interest cost	2	4	7	10
Expected return on plan assets	(2)	(2)	(5)	(6)
Prior service costs	(1)	(3)	(4)	(7)
Actuarial loss	0	0	1	1
Net Periodic Benefit Cost	$ 0	$ 0	$ 1	$ 0

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Mar. 31, 2021	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Class of Stock [Line Items]
Treasury stock, shares (in shares)		116,928		116,928		413,782
Release of common stock held in trust (in shares)		0	0	292,594	213
Number of shares repurchased during period (in shares)	53,311
Treasury shares (in shares)		357,146		357,146
Repurchases of common stock		$ 16		$ 16		$ 14
Iberdrola Renewables Holding, Inc
Class of Stock [Line Items]
Percentage of equity owned by parent		81.50%		81.50%
Convertible Preferred Stock
Class of Stock [Line Items]
Convertible preferred stock, shares outstanding (in shares)		0		0		0

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	$ 19,835	$ 15,869	$ 15,826	$ 15,539
Other comprehensive income (loss), net of tax	(74)	(6)	(172)	(19)
Balance, end of period	19,826	15,807	19,826	15,807
Unrealized loss from equity method investment, tax expense (benefit)	1	0	(3)	0
Unrealized loss on derivatives qualifying as cash flow hedges, taxes	(23)	(3)	(49)	(8)
Reclassification to net income of losses on cash flow hedges, taxes	(2)	0	(6)	1
Change in revaluation of defined benefit plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(12)	(12)	(12)	(12)
Other comprehensive income (loss), net of tax	0	0	0	0
Balance, end of period	(12)	(12)	(12)	(12)
Loss on nonqualified pension plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(20)	(7)	(20)	(7)
Other comprehensive income (loss), net of tax	0	0	0	0
Balance, end of period	(20)	(7)	(20)	(7)
Unrealized loss from equity method investment, net of income tax expense (benefit)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(3)	0	0	0
Other comprehensive income (loss), net of tax	(6)	0	(9)	0
Balance, end of period	(9)	0	(9)	0
Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax benefit
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(135)	(29)	(35)	(13)
Other comprehensive income (loss), net of tax	(73)	(15)	(173)	(31)
Balance, end of period	(208)	(44)	(208)	(44)
Reclassification to net income of (gains) losses on cash flow hedges, net of income tax (benefit) expense
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(39)	(60)	(44)	(63)
Other comprehensive income (loss), net of tax	5	9	10	12
Balance, end of period	(34)	(51)	(34)	(51)
(Loss) Gain on derivatives qualifying as cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(174)	(89)	(79)	(76)
Other comprehensive income (loss), net of tax	(68)	(6)	(163)	(19)
Balance, end of period	(242)	(95)	(242)	(95)
Accumulated Other Comprehensive Loss
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(209)	(108)	(111)	(95)
Other comprehensive income (loss), net of tax	(74)	(6)	(172)	(19)
Balance, end of period	$ (283)	$ (114)	$ (283)	$ (114)

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Numerator:
Net income attributable to AVANGRID	$ 111	$ 87	$ 543	$ 415
Denominator:
Weighted average number of shares outstanding - basic (in shares)	387,321,484	309,491,082	348,264,388	309,496,234
Weighted average number of shares outstanding - diluted (in shares)	387,676,085	309,550,126	348,714,535	309,554,838
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic (in dollars per share)	$ 0.29	$ 0.28	$ 1.56	$ 1.34
Earnings Per Common Share, Diluted (in dollars per share)	$ 0.29	$ 0.28	$ 1.56	$ 1.34

Segment Information - Additiona

Segment Information - Additional Information (Details)	9 Months Ended
	Sep. 30, 2021segment
Segment Reporting Information [Line Items]
Number of reportable segments	2
Networks
Segment Reporting Information [Line Items]
Number of reportable segments	1
Number of operating segments	9

Segment Information - By Segmen

Segment Information - By Segment (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Segment Reporting Information [Line Items]
Revenues	$ 1,598	$ 1,470	$ 5,041	$ 4,651
Depreciation and amortization	259	255	756	748
Operating income	138	165	675	647
Earnings (losses) from equity method investments	(1)	1	4	(3)
Interest expense, net of capitalization	70	86	218	251
Income tax expense (benefit)	(24)	15	0	21
Adjusted net income	133	100	609	434
Capital expenditures			1,897	1,960
Property, plant and equipment	28,158		28,158		$ 26,751
Equity method investments	571		571		668
Total assets	38,879		38,879		37,823
Corporate And Eliminations
Segment Reporting Information [Line Items]
Revenues	(2)	1	(1)	1
Depreciation and amortization	0	0	1	1
Operating income	(2)	(2)	(1)	6
Earnings (losses) from equity method investments	0	0	0	0
Interest expense, net of capitalization	19	24	61	53
Income tax expense (benefit)	(6)	2	(18)	(1)
Adjusted net income	(15)	(31)	(39)	(53)
Capital expenditures			0	0
Property, plant and equipment	9		9		10
Equity method investments	0		0		0
Total assets	677		677		364
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	0	(4)	(1)	(5)
Networks
Segment Reporting Information [Line Items]
Revenues	1,357	1,197	4,149	3,779
Networks | Operating Segments
Segment Reporting Information [Line Items]
Revenues	1,357	1,194	4,148	3,775
Depreciation and amortization	156	151	461	446
Operating income	158	160	618	617
Earnings (losses) from equity method investments	3	3	10	8
Interest expense, net of capitalization	51	63	157	199
Income tax expense (benefit)	8	20	74	75
Adjusted net income	130	99	467	379
Capital expenditures			1,512	1,312
Property, plant and equipment	18,206		18,206		17,079
Equity method investments	141		141		134
Total assets	25,930		25,930		24,592
Networks | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	0	3	1	4
Renewables
Segment Reporting Information [Line Items]
Revenues	243	276	894	876
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Revenues	243	275	894	875
Depreciation and amortization	103	104	294	301
Operating income	(18)	7	58	24
Earnings (losses) from equity method investments	(4)	(2)	(6)	(11)
Interest expense, net of capitalization	0	(1)	0	(1)
Income tax expense (benefit)	(26)	(7)	(56)	(53)
Adjusted net income	18	32	182	108
Capital expenditures			385	648
Property, plant and equipment	9,943		9,943		9,662
Equity method investments	430		430		534
Total assets	12,272		12,272		$ 12,867
Renewables | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	$ 0	$ 1	$ 0	$ 1

Segment Information - Reconcili

Segment Information - Reconciliation of Adjusted Net Income to Net Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.	$ 133	$ 100	$ 609	$ 434
Adjustments:
Mark-to-market earnings - Renewables	(9)	(7)	(50)	9
Restructuring charges	0	(1)	0	(5)
Accelerated depreciation from repowering	0	(3)	0	(9)
Impact of COVED -19	(19)	(8)	(33)	(21)
Merger costs	(3)	0	(6)	0
Income tax impact of adjustments	8	5	24	7
Net Income Attributable to Avangrid, Inc.	$ 111	$ 87	$ 543	$ 415

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Iberdrola Renovables Energía, S.L.
Related Party Transaction [Line Items]
Purchases From	$ (3)	$ (2)	$ (8)	$ (6)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Purchases From	(4)	(3)	(7)	(5)
Iberdrola
Related Party Transaction [Line Items]
Purchases From	(14)	(10)	(41)	(31)
Vineyard Wind
Related Party Transaction [Line Items]
Sales To	4	3	12	7
Iberdrola Solutions
Related Party Transaction [Line Items]
Sales To	(1)	2	7	2
Purchases From			(39)
Other
Related Party Transaction [Line Items]
Sales To			1
Purchases From	$ (1)	$ (1)	$ (2)	$ (2)

Related Party Transactions - _2

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Iberdrola
Related Party Transaction [Line Items]
Owed By	$ 2	$ 2
Owed To	(34)	(43)
Iberdrola Renovables Energía, S.L.
Related Party Transaction [Line Items]
Owed To	(8)	0
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Owed To	(7)	(6)
Vineyard Wind
Related Party Transaction [Line Items]
Owed By	5	4
Iberdrola Solutions
Related Party Transaction [Line Items]
Owed By		5
Owed To	$ (3)
Other
Related Party Transaction [Line Items]
Owed By		1
Owed To		$ (1)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2020	Dec. 14, 2020
Related Party Transaction [Line Items]
Deposit balance	$ 0	$ 0
AVANGRID | Iberdrola Loan | Subordinated Debt
Related Party Transaction [Line Items]
Face amount of debt			$ 3,000,000,000
Iberdrola Solutions
Related Party Transaction [Line Items]
Notes payable	2,000,000	5,000,000
Affiliated Entity
Related Party Transaction [Line Items]
Impairments	0
Iberdrola Financiacion, S.A.U
Related Party Transaction [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000
Credit facility, commitment fee percentage	0.105%
Credit facility outstanding amount	$ 0	$ 0

Other Financial Statement Ite_3

Other Financial Statement Items - Accounts Receivable and Unbilled Revenue (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Balance Sheet Related Disclosures [Abstract]
Trade receivables and unbilled revenues	$ 1,279	$ 1,295
Allowance for credit losses	(174)	(108)
Accounts receivable and unbilled revenues, net	$ 1,105	$ 1,187

Other Financial Statement Ite_4

Other Financial Statement Items - Allowance For Credit Losses (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 174	$ 94	$ 174	$ 94
Current period provision	41	19	106	60
Write-off as uncollectible	(17)	(10)	(40)	(35)
Ending balance	$ 150	$ 85	$ 108	$ 69

Other Financial Statement Ite_5

Other Financial Statement Items - Additional Information (Details) $ in Millions	May 13, 2021USD ($)project	Sep. 30, 2021USD ($)	Sep. 30, 2020USD ($)	Sep. 30, 2021USD ($)	Sep. 30, 2020USD ($)	Sep. 24, 2021USD ($)	Jun. 30, 2021USD ($)	Apr. 28, 2021USD ($)	Dec. 31, 2020USD ($)	Jun. 30, 2020USD ($)	Dec. 31, 2019USD ($)
Supplemental Balance Sheet Information [Line Items]
Allowance for doubtful accounts, deferred payment arrangement		$ 174	$ 94	$ 174	$ 94		$ 150		$ 108	$ 85	$ 69
Provision for doubtful accounts, accounts receivable		41	19	106	60
Prepaid other taxes		231		231					135
Accrued liabilities for property, plant and equipment additions		367	370	367	370
Commercial paper outstanding		0		0					309
Solar Projects In Nevada | Disposed of by Sale
Supplemental Balance Sheet Information [Line Items]
Percentage disposed	100.00%
Number of projects disposed | project	2
Consideration from disposition	$ 35
Gain on disposal, net of tax	3
Pre-tax gain on disposal	$ 4
$500 million Credit Facility
Supplemental Balance Sheet Information [Line Items]
Face amount of debt								$ 500
Unsecured Notes Maturing in 2031 | Unsecured Debt
Supplemental Balance Sheet Information [Line Items]
Face amount of debt						$ 350
Debt instrument, interest rate						2.15%
Supplier Financing Arrangements
Supplemental Balance Sheet Information [Line Items]
Notes payable, fair value		$ 97		$ 97					0
Debt, weighted average interest rate		1.08%		1.08%
Deferred Payment Arrangements
Supplemental Balance Sheet Information [Line Items]
Accounts receivable		$ 103		$ 103					78
Allowance for doubtful accounts, deferred payment arrangement		69		69					$ 48
Provision for doubtful accounts, accounts receivable		$ 7	$ 3	$ 21	$ 4

Other Financial Statement Ite_6

Other Financial Statement Items - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Property, plant and equipment
Accumulated depreciation	$ 10,421	$ 9,799
Intangible assets
Accumulated amortization	$ 329	$ 319

Income Tax Expense (Details)

Income Tax Expense (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Income Tax Disclosure [Abstract]
Effective income tax rate	(30.00%)	15.60%	0.00%	5.10%

Stock-Based Compensation Expe_2

Stock-Based Compensation Expense (Details) $ / shares in Units, $ in Millions	Mar. 15, 2021instrument$ / sharesshares	Feb. 15, 2021instrument$ / sharesshares	Jun. 30, 2021$ / sharesshares	Mar. 31, 2021USD ($)shares	Feb. 28, 2021shares	Aug. 31, 2020installment$ / sharesshares	Mar. 31, 2020installmentshares	Feb. 29, 2020installmentshares	Oct. 31, 2018$ / sharesshares	Sep. 30, 2021USD ($)	Sep. 30, 2020USD ($)	Sep. 30, 2021USD ($)	Sep. 30, 2020USD ($)	Dec. 31, 2020USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $										$ 5	$ 1	$ 14	$ 12
Performance Shares Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)	75,000	1,181,031						208,268
Number of vesting installments	3	3						3
Number of shares issued (in shares)				45,661
Grant date fair value (in dollars per share) | $ / shares	$ 36.22	$ 36.22
Award requisite service period												4 years
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issued (in shares)			9,390						5,953
Restricted Stock Units (RSUs) | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)			17,500			5,000			8,000
Number of vesting installments | installment						3
Number of shares issued (in shares)					1,697
Grant date fair value (in dollars per share) | $ / shares			$ 53.59			$ 48.99			$ 47.59
Phantom Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)							167,060
Number of vesting installments | installment							3
Cash used to settle award | $				$ 2
Share based compensation liability | $										$ 2		$ 2		$ 2

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	Sep. 09, 2021USD ($)	Feb. 05, 2021wind_farmMW	Sep. 30, 2021USD ($)	Sep. 30, 2021USD ($)	Sep. 30, 2020USD ($)	Dec. 31, 2020USD ($)
Variable Interest Entity [Line Items]
Wind farms expected to be part of Aeolus VII | wind_farm		4
Proposed wind farm and electricity transmission project capacity (in MW) | MW		688
Equity adjustment from sale of TEFs			$ 131	$ 141	$ 312
Assets of variable interest entities (VIEs)			38,879	38,879		$ 37,823
Liabilities of variable interest entities (VIEs)			19,053	19,053		21,997
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Proceeds from sale of TEFs	$ 131
Equity adjustment from sale of TEFs	8
Noncontrolling interest in VIE	$ 139
Assets of variable interest entities (VIEs)			1,649	1,649		1,713
Liabilities of variable interest entities (VIEs)			$ 72	$ 72		$ 107

Equity Method Investments (Deta

Equity Method Investments (Details) $ in Millions	Feb. 05, 2021MW	Dec. 31, 2020USD ($)	Dec. 31, 2019MW	Sep. 30, 2021USD ($)alease_areaeasementMW	Dec. 31, 2019USD ($)	Dec. 31, 2018MW	Sep. 15, 2021USD ($)
Schedule of Equity Method Investments [Line Items]
Proposed wind farm and electricity transmission project capacity (in MW) | MW	688
Equity method investments		$ 668		$ 571
Vineyard Wind, LLC
Schedule of Equity Method Investments [Line Items]
Number of easements acquired | easement				2
Number of lease areas | lease_area				2
Leased are transmission capacity (in MW) | MW				5,000
Area of land (in acres) | a				166,886
Proposed wind farm and electricity transmission project capacity (in MW) | MW			804			800
Renewables
Schedule of Equity Method Investments [Line Items]
Amount contributed to acquire easement contract					$ 100
Joint Venture With CIP
Schedule of Equity Method Investments [Line Items]
Amount of guaranty issued							$ 827
Amount contributed to acquire easement contract, returned							136
Joint venture restructuring agreement, payment to the other party							168
Equity method investments		245		$ 156
Joint Venture With CIP | Letter of Credit
Schedule of Equity Method Investments [Line Items]
Line of credit facility, maximum borrowing capacity							$ 1,200
Joint Venture With CIP | Copenhagen Infrastructure Partners (CIP)
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			50.00%		50.00%
Joint Venture With CIP | Renewables
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage				50.00%
Joint venture, reimbursements received		$ 33